In situ thermal processing and remediation of an oil shale formation

ABSTRACT

An oil shale formation may be treated using an in situ thermal process. Heat may be provided to a portion of the formation from one or more heat sources. Heat may be allowed to transfer from the heat sources to a selection of the formation. Hydrocarbons, H 2 , and/or other formation fluids may be produced from the formation. A recovery fluid may be provided to the formation to recover one or more components remaining in the portion.

PRIORITY CLAIM

[0001] This application claims priority to Provisional PatentApplication No. 60/286,062 entitled “IN SITU THERMAL PROCESSING OF OILSHALE” filed on Apr. 24, 2001 and to Provisional Patent Application No.60/337,249 entitled “IN SITU THERMAL PROCESSING OF AN OIL SHALEFORMATION” filed on Oct. 24, 2001.

BACKGROUND OF THE INVENTION

[0002] 1. Field of the Invention

[0003] The present invention relates generally to methods and systemsfor production of hydrocarbons, hydrogen, and/or other products fromvarious oil shale formations. Certain embodiments relate to in situconversion of hydrocarbons to produce hydrocarbons, hydrogen, and/ornovel product streams from underground oil shale formations.

[0004] 2. Description of Related Art

[0005] Hydrocarbons obtained from subterranean (e.g., sedimentary)formations are often used as energy resources, as feedstocks, and asconsumer products. Concerns over depletion of available hydrocarbonresources and over declining overall quality of produced hydrocarbonshave led to development of processes for more efficient recovery,processing and/or use of available hydrocarbon resources. In situprocesses may be used to remove hydrocarbon materials from subterraneanformations. Chemical and/or physical properties of hydrocarbon materialwithin a subterranean formation may need to be changed to allowhydrocarbon material to be more easily removed from the subterraneanformation. The chemical and physical changes may include in situreactions that produce removable fluids, composition changes, solubilitychanges, density changes, phase changes, and/or viscosity changes of thehydrocarbon material within the formation. A fluid may be, but is notlimited to, a gas, a liquid, an emulsion, a slurry, and/or a stream ofsolid particles that has flow characteristics similar to liquid flow.

[0006] Examples of in situ processes utilizing downhole heaters areillustrated in U.S. Pat. Nos. 2,634,961 to Ljungstrom, 2,732,195 toLjungstrom, 2,780,450 to Ljungstrom, 2,789,805 to Ljungstrom, 2,923,535to Ljungstrom, and 4,886,118 to Van Meurs et al., each of which isincorporated by reference as if fully set forth herein.

[0007] Application of heat to oil shale formations is described in U.S.Pat. Nos. 2,923,535 to Ljungstrom and 4,886,118 to Van Meurs et al. Heatmay be applied to the oil shale formation to pyrolyze kerogen within theoil shale formation. The heat may also fracture the formation toincrease permeability of the formation. The increased permeability mayallow formation fluid to travel to a production well where the fluid isremoved from the oil shale formation. In some processes disclosed byLjungstrom, for example, an oxygen containing gaseous medium isintroduced to a permeable stratum, preferably while still hot from apreheating step, to initiate combustion.

[0008] A heat source may be used to heat a subterranean formation.Electric heaters may be used to heat the subterranean formation byradiation and/or conduction. An electric heater may resistively heat anelement. U.S. Pat. No. 2,548,360 to Germain, which is incorporated byreference as if fully set forth herein, describes an electric heatingelement placed within a viscous oil within a wellbore. The heaterelement heats and thins the oil to allow the oil to be pumped from thewellbore. U.S. Pat. No. 4,716,960 to Eastlund et al., which isincorporated by reference as if fully set forth herein, describeselectrically heating tubing of a petroleum well by passing a relativelylow voltage current through the tubing to prevent formation of solids.U.S. Pat. No. 5,065,818 to Van Egmond, which is incorporated byreference as if fully set forth herein, describes an electric heatingelement that is cemented into a well borehole without a casingsurrounding the heating element.

[0009] U.S. Pat. No. 6,023,554 to Vinegar et al., which is incorporatedby reference as if fully set forth herein, describes an electric heatingelement that is positioned within a casing. The heating elementgenerates radiant energy that heats the casing. A granular solid fillmaterial may be placed between the casing and the formation. The casingmay conductively heat the fill material, which in turn conductivelyheats the formation.

[0010] U.S. Pat. No. 4,570,715 to Van Meurs et al., which isincorporated by reference as if fully set forth herein, describes anelectric heating element. The heating element has an electricallyconductive core, a surrounding layer of insulating material, and asurrounding metallic sheath. The conductive core may have a relativelylow resistance at high temperatures. The insulating material may haveelectrical resistance, compressive strength, and heat conductivityproperties that are relatively high at high temperatures. The insulatinglayer may inhibit arcing from the core to the metallic sheath. Themetallic sheath may have tensile strength and creep resistanceproperties that are relatively high at high temperatures.

[0011] U.S. Pat. No. 5,060,287 to Van Egmond, which is incorporated byreference as if fully set forth herein, describes an electrical heatingelement having a copper-nickel alloy core.

[0012] Combustion of a fuel may be used to heat a formation. Combustinga fuel to heat a formation may be more economical than using electricityto heat a formation. Several different types of heaters may use fuelcombustion as a heat source that heats a formation. The combustion maytake place in the formation, in a well, and/or near the surface.Combustion in the formation may be a fireflood. An oxidizer may bepumped into the formation. The oxidizer may be ignited to advance a firefront towards a production well. Oxidizer pumped into the formation mayflow through the formation along fracture lines in the formation.Ignition of the oxidizer may not result in the fire front flowinguniformly through the formation.

[0013] A flameless combustor may be used to combust a fuel within awell. U.S. Pat. Nos. 5,255,742 to Mikus, 5,404,952 to Vinegar et al.,5,862,858 to Wellington et al., and 5,899,269 to Wellington et al.,which are incorporated by reference as if fully set forth herein,describe flameless combustors. Flameless combustion may be accomplishedby preheating a fuel and combustion air to a temperature above anauto-ignition temperature of the mixture. The fuel and combustion airmay be mixed in a heating zone to combust. In the heating zone of theflameless combustor, a catalytic surface may be provided to lower theauto-ignition temperature of the fuel and air mixture.

[0014] Heat may be supplied to a formation from a surface heater. Thesurface heater may produce combustion gases that are circulated throughwellbores to heat the formation. Alternately, a surface burner may beused to heat a heat transfer fluid that is passed through a wellbore toheat the formation. Examples of fired heaters, or surface burners thatmay be used to heat a subterranean formation, are illustrated in U.S.Pat. Nos. 6,056,057 to Vinegar et al. and 6,079,499 to Mikus et al.,which are both incorporated by reference as if fully set forth herein.

[0015] Synthesis gas may be produced in reactors or in situ within asubterranean formation. Synthesis gas may be produced within a reactorby partially oxidizing methane with oxygen. In situ production ofsynthesis gas may be economically desirable to avoid the expense ofbuilding, operating, and maintaining a surface synthesis gas productionfacility. U.S. Pat. No. 4,250,230 to Terry, which is incorporated byreference as if fully set forth herein, describes a system for in situgasification of coal. A subterranean coal seam is burned from a firstwell towards a production well. Methane, hydrocarbons, H₂, CO, and otherfluids may be removed from the formation through the production well.The H₂ and CO may be separated from the remaining fluid. The H₂ and COmay be sent to fuel cells to generate electricity.

[0016] U.S. Pat. No. 4,057,293 to Garrett, which is incorporated byreference as if fully set forth herein, discloses a process forproducing synthesis gas. A portion of a rubble pile is burned to heatthe rubble pile to a temperature that generates liquid and gaseoushydrocarbons by pyrolysis. After pyrolysis, the rubble is furtherheated, and steam or steam and air are introduced to the rubble pile togenerate synthesis gas.

[0017] U.S. Pat. No. 5,554,453 to Steinfeld et al., which isincorporated by reference as if fully set forth herein, describes an exsitu coal gasifier that supplies fuel gas to a fuel cell. The fuel cellproduces electricity. A catalytic burner is used to burn exhaust gasfrom the fuel cell with an oxidant gas to generate heat in the gasifier.

[0018] Carbon dioxide may be produced from combustion of fuel and frommany chemical processes. Carbon dioxide may be used for variouspurposes, such as, but not limited to, a feed stream for a dry iceproduction facility, supercritical fluid in a low temperaturesupercritical fluid process, a flooding agent for coal beddemethanation, and a flooding agent for enhanced oil recovery. Althoughsome carbon dioxide is productively used, many tons of carbon dioxideare vented to the atmosphere.

[0019] Retorting processes for oil shale may be generally divided intotwo major types: aboveground (surface) and underground (in situ).Aboveground retorting of oil shale typically involves mining andconstruction of metal vessels capable of withstanding high temperatures.The quality of oil produced from such retorting may typically be poor,thereby requiring costly upgrading. Aboveground retorting may alsoadversely affect environmental and water resources due to mining,transporting, processing, and/or disposing of the retorted material.Many U.S. patents have been issued relating to aboveground retorting ofoil shale. Currently available aboveground retorting processes include,for example, direct, indirect, and/or combination heating methods.

[0020] In situ retorting typically involves retorting oil shale withoutremoving the oil shale from the ground by mining. “Modified” in situprocesses typically require some mining to develop underground retortchambers. An example of a “modified” in situ process includes a methoddeveloped by Occidental Petroleum that involves mining approximately 20%of the oil shale in a formation, explosively rubblizing the remainder ofthe oil shale to fill up the mined out area, and combusting the oilshale by gravity stable combustion in which combustion is initiated fromthe top of the retort. Other examples of “modified” in situ processesinclude the “Rubble In Situ Extraction” (“RISE”) method developed by theLawrence Livermore Laboratory (“LLL”) and radio-frequency methodsdeveloped by IIT Research Institute (“IITRI”) and LLL, which involvetunneling and mining drifts to install an array of radio-frequencyantennas in an oil shale formation.

[0021] Obtaining permeability within an oil shale formation (e.g.,between injection and production wells) tends to be difficult becauseoil shale is often substantially impermeable. Many methods haveattempted to link injection and production wells, including: hydraulicfracturing such as methods investigated by Dow Chemical and LaramieEnergy Research Center; electrical fracturing (e.g., by methodsinvestigated by Laramie Energy Research Center); acid leaching oflimestone cavities (e.g., by methods investigated by Dow Chemical);steam injection into permeable nahcolite zones to dissolve the nahcolite(e.g., by methods investigated by Shell Oil and Equity Oil); fracturingwith chemical explosives (e.g., by methods investigated by Talley EnergySystems); fracturing with nuclear explosives (e.g., by methodsinvestigated by Project Bronco); and combinations of these methods. Manyof such methods, however, have relatively high operating costs and lacksufficient injection capacity.

[0022] An example of an in situ retorting process is illustrated in U.S.Pat. No. 3,241,611 to Dougan, assigned to Equity Oil Company, which isincorporated by reference as if fully set forth herein. For example,Dougan discloses a method involving the use of natural gas for conveyingkerogen-decomposing heat to the formation. The heated natural gas may beused as a solvent for thermally decomposed kerogen. The heated naturalgas exercises a solvent-stripping action with respect to the oil shaleby penetrating pores that exist in the shale. The natural gas carrierfluid, accompanied by decomposition product vapors and gases, passesupwardly through extraction wells into product recovery lines, and intoand through condensers interposed in such lines, where the decompositionvapors condense, leaving the natural gas carrier fluid to flow through aheater and into an injection well drilled into the deposit of oil shale.

[0023] U.S. Pat. Nos. 5,297,626 Vinegar et al. and 5,392,854 to Vinegaret al., which are incorporated by reference as if fully set forthherein, describe a process wherein an oil containing subterraneanformation is heated. The following patents are incorporated herein byreference: U.S. Pat. Nos. 6,152,987 to Ma et al.; 5,525,322 to Willms;5,861,137 to Edlund; and 5,229,102 to Minet et al.

[0024] As outlined above, there has been a significant amount of effortto develop methods and systems to economically produce hydrocarbons,hydrogen, and/or other products from oil shale formations. At present,however, there are still many oil shale formations from whichhydrocarbons, hydrogen, and/or other products cannot be economicallyproduced. Thus, there is still a need for improved methods and systemsfor production of hydrocarbons, hydrogen, and/or other products fromvarious oil shale formations.

SUMMARY OF THE INVENTION

[0025] In an embodiment, hydrocarbons within an oil shale formation maybe converted in situ within the formation to yield a mixture ofrelatively high quality hydrocarbon products, hydrogen, and/or otherproducts. One or more heat sources may be used to heat a portion of theoil shale formation to temperatures that allow pyrolysis of thehydrocarbons. Hydrocarbons, hydrogen, and other formation fluids may beremoved from the formation through one or more production wells. In someembodiments, formation fluids may be removed in a vapor phase. In otherembodiments, formation fluids may be removed in liquid and vapor phasesor in a liquid phase. Temperature and pressure in at least a portion ofthe formation may be controlled during pyrolysis to yield improvedproducts from the formation.

[0026] In an embodiment, one or more heat sources may be installed intoa formation to heat the formation. Heat sources may be installed bydrilling openings (well bores) into the formation. In some embodiments,openings may be formed in the formation using a drill with a steerablemotor and an accelerometer. Alternatively, an opening may be formed intothe formation by geosteered drilling. Alternately, an opening may beformed into the formation by sonic drilling.

[0027] One or more heat sources may be disposed within the opening suchthat the heat sources transfer heat to the formation. For example, aheat source may be placed in an open wellbore in the formation. Heat mayconductively and radiatively transfer from the heat source to theformation. Alternatively, a heat source may be placed within a heaterwell that may be packed with gravel, sand, and/or cement. The cement maybe a refractory cement.

[0028] In some embodiments, one or more heat sources may be placed in apattern within the formation. For example, in one embodiment, an in situconversion process for hydrocarbons may include heating at least aportion of an oil shale formation with an array of heat sources disposedwithin the formation. In some embodiments, the array of heat sources canbe positioned substantially equidistant from a production well. Certainpatterns (e.g., triangular arrays, hexagonal arrays, or other arraypatterns) may be more desirable for specific applications. In addition,the array of heat sources may be disposed such that a distance betweeneach heat source may be less than about 70 feet (21 m). In addition, thein situ conversion process for hydrocarbons may include heating at leasta portion of the formation with heat sources disposed substantiallyparallel to a boundary of the hydrocarbons. Regardless of thearrangement of or distance between the heat sources, in certainembodiments, a ratio of heat sources to production wells disposed withina formation may be greater than about 3, 5, 8, 10, 20, or more.

[0029] Certain embodiments may also include allowing heat to transferfrom one or more of the heat sources to a selected section of the heatedportion. In an embodiment, the selected section may be disposed betweenone or more heat sources. For example, the in situ conversion processmay also include allowing heat to transfer from one or more heat sourcesto a selected section of the formation such that heat from one or moreof the heat sources pyrolyzes at least some hydrocarbons within theselected section. The in situ conversion process may include heating atleast a portion of an oil shale formation above a pyrolyzationtemperature of hydrocarbons in the formation. For example, apyrolyzation temperature may include a temperature of at least about270° C. Heat may be allowed to transfer from one or more of the heatsources to the selected section substantially by conduction.

[0030] One or more heat sources may be located within the formation suchthat superposition of heat produced from one or more heat sources mayoccur. Superposition of heat may increase a temperature of the selectedsection to a temperature sufficient for pyrolysis of at least some ofthe hydrocarbons within the selected section. Superposition of heat mayvary depending on, for example, a spacing between heat sources. Thespacing between heat sources may be selected to optimize heating of thesection selected for treatment. Therefore, hydrocarbons may be pyrolyzedwithin a larger area of the portion. Spacing between heat sources may beselected to increase the effectiveness of the heat sources, therebyincreasing the economic viability of a selected in situ conversionprocess for hydrocarbons. Superposition of heat tends to increase theuniformity of heat distribution in the section of the formation selectedfor treatment.

[0031] Various systems and methods may be used to provide heat sources.In an embodiment, a natural distributed combustor system and method mayheat at least a portion of an oil shale formation. The system and methodmay first include heating a first portion of the formation to atemperature sufficient to support oxidation of at least some of thehydrocarbons therein. One or more conduits may be disposed within one ormore openings. One or more of the conduits may provide an oxidizingfluid from an oxidizing fluid source into an opening in the formation.The oxidizing fluid may oxidize at least a portion of the hydrocarbonsat a reaction zone within the formation. Oxidation may generate heat atthe reaction zone. The generated heat may transfer from the reactionzone to a pyrolysis zone in the formation. The heat may transfer byconduction, radiation, and/or convection. A heated portion of theformation may include the reaction zone and the pyrolysis zone. Theheated portion may also be located adjacent to the opening. One or moreof the conduits may remove one or more oxidation products from thereaction zone and/or the opening in the formation. Alternatively,additional conduits may remove one or more oxidation products from thereaction zone and/or formation.

[0032] In certain embodiments, the flow of oxidizing fluid may becontrolled along at least a portion of the length of the reaction zone.In some embodiments, hydrogen may be allowed to transfer into thereaction zone.

[0033] In an embodiment, a system and a method may include an opening inthe formation extending from a first location on the surface of theearth to a second location on the surface of the earth. For example, theopening may be substantially U-shaped. Heat sources may be placed withinthe opening to provide heat to at least a portion of the formation.

[0034] A conduit may be positioned in the opening extending from thefirst location to the second location. In an embodiment, a heat sourcemay be positioned proximate and/or in the conduit to provide heat to theconduit. Transfer of the heat through the conduit may provide heat to aselected section of the formation. In some embodiments, an additionalheater may be placed in an additional conduit to provide heat to theselected section of the formation through the additional conduit.

[0035] In some embodiments, an annulus is formed between a wall of theopening and a wall of the conduit placed within the opening extendingfrom the first location to the second location. A heat source may beplace proximate and/or in the annulus to provide heat to a portion theopening. The provided heat may transfer through the annulus to aselected section of the formation.

[0036] In an embodiment, a system and method for heating an oil shaleformation may include one or more insulated conductors disposed in oneor more openings in the formation. The openings may be uncased.Alternatively, the openings may include a casing. As such, the insulatedconductors may provide conductive, radiant, or convective heat to atleast a portion of the formation. In addition, the system and method mayallow heat to transfer from the insulated conductor to a section of theformation. In some embodiments, the insulated conductor may include acopper-nickel alloy. In some embodiments, the insulated conductor may beelectrically coupled to two additional insulated conductors in a 3-phaseY configuration.

[0037] An embodiment of a system and method for heating an oil shaleformation may include a conductor placed within a conduit (e.g., aconductor-in-conduit heat source). The conduit may be disposed withinthe opening. An electric current may be applied to the conductor toprovide heat to a portion of the formation. The system may allow heat totransfer from the conductor to a section of the formation during use. Insome embodiments, an oxidizing fluid source may be placed proximate anopening in the formation extending from the first location on theearth's surface to the second location on the earth's surface. Theoxidizing fluid source may provide oxidizing fluid to a conduit in theopening. The oxidizing fluid may transfer from the conduit to a reactionzone in the formation. In an embodiment, an electrical current may beprovided to the conduit to heat a portion of the conduit. The heat maytransfer to the reaction zone in the oil shale formation. Oxidizingfluid may then be provided to the conduit. The oxidizing fluid mayoxidize hydrocarbons in the reaction zone, thereby generating heat. Thegenerated heat may transfer to a pyrolysis zone and the transferred heatmay pyrolyze hydrocarbons within the pyrolysis zone.

[0038] In some embodiments, an insulation layer may be coupled to aportion of the conductor. The insulation layer may electrically insulateat least a portion of the conductor from the conduit during use.

[0039] In an embodiment, a conductor-in-conduit heat source having adesired length may be assembled. A conductor may be placed within theconduit to form the conductor-in-conduit heat source. Two or moreconductor-in-conduit heat sources may be coupled together to form a heatsource having the desired length. The conductors of theconductor-in-conduit heat sources may be electrically coupled together.In addition, the conduits may be electrically coupled together. Adesired length of the conductor-in-conduit may be placed in an openingin the oil shale formation. In some embodiments, individual sections ofthe conductor-in-conduit heat source may be coupled using shieldedactive gas welding.

[0040] In some embodiments, a centralizer may be used to inhibitmovement of the conductor within the conduit. A centralizer may beplaced on the conductor as a heat source is made. In certainembodiments, a protrusion may be placed on the conductor to maintain thelocation of a centralizer.

[0041] In certain embodiments, a heat source of a desired length may beassembled proximate the oil shale formation. The assembled heat sourcesmay then be coiled. The heat source may be placed in the oil shaleformation by uncoiling the heat source into the opening in the oil shaleformation.

[0042] In certain embodiments, portions of the conductors may include anelectrically conductive material. Use of the electrically conductivematerial on a portion (e.g., in the overburden portion) of the conductormay lower an electrical resistance of the conductor.

[0043] A conductor placed in a conduit may be treated to increase theemissivity of the conductor, in some embodiments. The emissivity of theconductor may be increased by roughening at least a portion of thesurface of the conductor. In certain embodiments, the conductor may betreated to increase the emissivity prior to being placed within theconduit. In some embodiments, the conduit may be treated to increase theemissivity of the conduit.

[0044] In an embodiment, a system and method may include one or moreelongated members disposed in an opening in the formation. Each of theelongated members may provide heat to at least a portion of theformation. One or more conduits may be disposed in the opening. One ormore of the conduits may provide an oxidizing fluid from an oxidizingfluid source into the opening. In certain embodiments, the oxidizingfluid may inhibit carbon deposition on or proximate the elongatedmember.

[0045] In certain embodiments, an expansion mechanism may be coupled toa heat source. The expansion mechanism may allow the heat source to moveduring use. For example, the expansion mechanism may allow for theexpansion of the heat source during use.

[0046] In one embodiment, an in situ method and system for heating anoil shale formation may include providing oxidizing fluid to a firstoxidizer placed in an opening in the formation. Fuel may be provided tothe first oxidizer and at least some fuel may be oxidized in the firstoxidizer. Oxidizing fluid may be provided to a second oxidizer placed inthe opening in the formation. Fuel may be provided to the secondoxidizer and at least some fuel may be oxidized in the second oxidizer.Heat from oxidation of fuel may be allowed to transfer to a portion ofthe formation.

[0047] An opening in an oil shale formation may include a firstelongated portion, a second elongated portion, and a third elongatedportion. Certain embodiments of a method and system for heating an oilshale formation may include providing heat from a first heater placed inthe second elongated portion. The second elongated portion may divergefrom the first elongated portion in a first direction. The thirdelongated portion may diverge from the first elongated portion in asecond direction. The first direction may be substantially differentthan the second direction. Heat may be provided from a second heaterplaced in the third elongated portion of the opening in the formation.Heat from the first heater and the second heater may be allowed totransfer to a portion of the formation.

[0048] An embodiment of a method and system for heating an oil shaleformation may include providing oxidizing fluid to a first oxidizerplaced in an opening in the formation. Fuel may be provided to the firstoxidizer and at least some fuel may be oxidized in the first oxidizer.The method may further include allowing heat from oxidation of fuel totransfer to a portion of the formation and allowing heat to transferfrom a heater placed in the opening to a portion of the formation.

[0049] In an embodiment, a system and method for heating an oil shaleformation may include oxidizing a fuel fluid in a heater. The method mayfurther include providing at least a portion of the oxidized fuel fluidinto a conduit disposed in an opening in the formation. In addition,additional heat may be transferred from an electric heater disposed inthe opening to the section of the formation. Heat may be allowed totransfer uniformly along a length of the opening.

[0050] Energy input costs may be reduced in some embodiments of systemsand methods described above. For example, an energy input cost may bereduced by heating a portion of an oil shale formation by oxidation incombination with heating the portion of the formation by an electricheater. The electric heater may be turned down and/or off when theoxidation reaction begins to provide sufficient heat to the formation.Electrical energy costs associated with heating at least a portion of aformation with an electric heater may be reduced. Thus, a moreeconomical process may be provided for heating an oil shale formation incomparison to heating by a conventional method. In addition, theoxidation reaction may be propagated slowly through a greater portion ofthe formation such that fewer heat sources may be required to heat sucha greater portion in comparison to heating by a conventional method.

[0051] Certain embodiments as described herein may provide a lower costsystem and method for heating an oil shale formation. For example,certain embodiments may more uniformly transfer heat along a length of aheater. Such a length of a heater may be greater than about 300 m orpossibly greater than about 600 m. In addition, in certain embodiments,heat may be provided to the formation more efficiently by radiation.Furthermore, certain embodiments of systems may have a substantiallylonger lifetime than presently available systems.

[0052] In an embodiment, an in situ conversion system and method forhydrocarbons may include maintaining a portion of the formation in asubstantially unheated condition. The portion may provide structuralstrength to the formation and/or confinement/isolation to certainregions of the formation. A processed oil shale formation may havealternating heated and substantially unheated portions arranged in apattern that may, in some embodiments, resemble a checkerboard pattern,or a pattern of alternating areas (e.g., strips) of heated and unheatedportions.

[0053] In an embodiment, a heat source may advantageously heat onlyalong a selected portion or selected portions of a length of the heater.For example, a formation may include several hydrocarbon containinglayers. One or more of the hydrocarbon containing layers may beseparated by layers containing little or no hydrocarbons. A heat sourcemay include several discrete high heating zones that may be separated bylow heating zones. The high heating zones may be disposed proximatehydrocarbon containing layers such that the layers may be heated. Thelow heating zones may be disposed proximate layers containing little orno hydrocarbons such that the layers may not be substantially heated.For example, an electric heater may include one or more low resistanceheater sections and one or more high resistance heater sections. Lowresistance heater sections of the electric heater may be disposed inand/or proximate layers containing little or no hydrocarbons. Inaddition, high resistance heater sections of the electric heater may bedisposed proximate hydrocarbon containing layers. In an additionalexample, a fueled heater (e.g., surface burner) may include insulatedsections. Insulated sections of the fueled heater may be placedproximate or adjacent to layers containing little or no hydrocarbons.Alternately, a heater with distributed air and/or fuel may be configuredsuch that little or no fuel may be combusted proximate or adjacent tolayers containing little or no hydrocarbons. Such a fueled heater mayinclude flameless combustors and natural distributed combustors.

[0054] In certain embodiments, the permeability of an oil shaleformation may vary within the formation. For example, a first sectionmay have a lower permeability than a second section. In an embodiment,heat may be provided to the formation to pyrolyze hydrocarbons withinthe lower permeability first section. Pyrolysis products may be producedfrom the higher permeability second section in a mixture ofhydrocarbons.

[0055] In an embodiment, a heating rate of the formation may be slowlyraised through the pyrolysis temperature range. For example, an in situconversion process for hydrocarbons may include heating at least aportion of an oil shale formation to raise an average temperature of theportion above about 270° C. by a rate less than a selected amount (e.g.,about 10° C., 5° C., 3° C., 1° C., 0.5° C., or 0.1° C.) per day. In afurther embodiment, the portion may be heated such that an averagetemperature of the selected section may be less than about 375° C. or,in some embodiments, less than about 400° C.

[0056] In an embodiment, a temperature of the portion may be monitoredthrough a test well disposed in a formation. For example, the test wellmay be positioned in a formation between a first heat source and asecond heat source. Certain systems and methods may include controllingthe heat from the first heat source and/or the second heat source toraise the monitored temperature at the test well at a rate of less thanabout a selected amount per day. In addition or alternatively, atemperature of the portion may be monitored at a production well. An insitu conversion process for hydrocarbons may include controlling theheat from the first heat source and/or the second heat source to raisethe monitored temperature at the production well at a rate of less thana selected amount per day.

[0057] An embodiment of an in situ method of measuring a temperaturewithin a wellbore may include providing a pressure wave from a pressurewave source into the wellbore. The wellbore may include a plurality ofdiscontinuities along a length of the wellbore. The method furtherincludes measuring a reflection signal of the pressure wave and usingthe reflection signal to assess at least one temperature between atleast two discontinuities.

[0058] Certain embodiments may include heating a selected volume of anoil shale formation. Heat may be provided to the selected volume byproviding power to one or more heat sources. Power may be defined asheating energy per day provided to the selected volume. A power (Pwr)required to generate a heating rate (h, in units of, for example, °C./day) in a selected volume (V) of an oil shale formation may bedetermined by EQN. 1:

Pwr=h*V*C _(v)*ρ_(B).  (1)

[0059] In this equation, an average heat capacity of the formation(C_(v)) and an average bulk density of the formation (ρ_(B)) may beestimated or determined using one or more samples taken from the oilshale formation.

[0060] Certain embodiments may include raising and maintaining apressure in an oil shale formation. Pressure may be, for example,controlled within a range of about 2 bars absolute to about 20 barsabsolute. For example, the process may include controlling a pressurewithin a majority of a selected section of a heated portion of theformation. The controlled pressure may be above about 2 bars absoluteduring pyrolysis. In an alternate embodiment, an in situ conversionprocess for hydrocarbons may include raising and maintaining thepressure in the formation within a range of about 20 bars absolute toabout 36 bars absolute.

[0061] In an embodiment, compositions and properties of formation fluidsproduced by an in situ conversion process for hydrocarbons may varydepending on, for example, conditions within an oil shale formation.

[0062] Certain embodiments may include controlling the heat provided toat least a portion of the formation such that production of lessdesirable products in the portion may be inhibited. Controlling the heatprovided to at least a portion of the formation may also increase theuniformity of permeability within the formation. For example,controlling the heating of the formation to inhibit production of lessdesirable products may, in some embodiments, include controlling theheating rate to less than a selected amount (e.g., 10° C., 5° C., 3° C.,1° C., 0.5° C., or 0.1° C.) per day.

[0063] Controlling pressure, heat and/or heating rates of a selectedsection in a formation may increase production of selected formationfluids. For example, the amount and/or rate of heating may be controlledto produce formation fluids having an American Petroleum Institute(“API”) gravity greater than about 25. Heat and/or pressure may becontrolled to inhibit production of olefins in the produced fluids.

[0064] Controlling formation conditions to control the pressure ofhydrogen in the produced fluid may result in improved qualities of theproduced fluids. In some embodiments, it may be desirable to controlformation conditions so that the partial pressure of hydrogen in aproduced fluid is greater than about 0.5 bars absolute, as measured at aproduction well.

[0065] In one embodiment, a method of treating an oil shale formation insitu may include adding hydrogen to the selected section after atemperature of the selected section is at least about 270° C. Otherembodiments may include controlling a temperature of the formation byselectively adding hydrogen to the formation.

[0066] In certain embodiments, an oil shale formation may be treated insitu with a heat transfer fluid such as steam. In an embodiment, amethod of formation may include injecting a heat transfer fluid into aformation. Heat from the heat transfer fluid may transfer to a selectedsection of the formation. The heat from the heat transfer fluid maypyrolyze a substantial portion of the hydrocarbons within the selectedsection of the formation. The produced gas mixture may includehydrocarbons with an average API gravity greater than about 25°.

[0067] Furthermore, treating an oil shale formation with a heat transferfluid may also mobilize hydrocarbons in the formation. In an embodiment,a method of treating a formation may include injecting a heat transferfluid into a formation, allowing the heat from the heat transfer fluidto transfer to a selected first section of the formation, and mobilizingand pyrolyzing at least some of the hydrocarbons within the selectedfirst section of the formation. At least some of the mobilizedhydrocarbons may flow from the selected first section of the formationto a selected second section of the formation. The heat may pyrolyze atleast some of the hydrocarbons within the selected second section of theformation. A gas mixture may be produced from the formation.

[0068] Another embodiment of treating a formation with a heat transferfluid may include a moving heat transfer fluid front. A method mayinclude injecting a heat transfer fluid into a formation and allowingthe heat transfer fluid to migrate through the formation. A size of aselected section may increase as a heat transfer fluid front migratesthrough an untreated portion of the formation. The selected section is aportion of the formation treated by the heat transfer fluid. Heat fromthe heat transfer fluid may transfer heat to the selected section. Theheat may pyrolyze at least some of the hydrocarbons within the selectedsection of the formation. The heat may also mobilize at least some ofthe hydrocarbons at the heat transfer fluid front. The mobilizedhydrocarbons may flow substantially parallel to the heat transfer fluidfront. The heat may pyrolyze at least a portion of the hydrocarbons inthe mobilized fluid and a gas mixture may be produced from theformation.

[0069] Simulations may be utilized to increase an understanding of insitu processes. Simulations may model heating of the formation from heatsources and the transfer of heat to a selected section of the formation.Simulations may require the input of model parameters, properties of theformation, operating conditions, process characteristics, and/or desiredparameters to determine operating conditions. Simulations may assessvarious aspects of an in situ process. For example, various aspects mayinclude, but not be limited to, deformation characteristics, heatingrates, temperatures within the formation, pressures, time to firstproduced fluids, and/or compositions of produced fluids.

[0070] Systems utilized in conducting simulations may include a centralprocessing unit (CPU), a data memory, and a system memory. The systemmemory and the data memory may be coupled to the CPU. Computer programsexecutable to implement simulations may be stored on the system memory.Carrier mediums may include program instructions that arecomputer-executable to simulate the in situ processes.

[0071] In one embodiment, a computer-implemented method and system oftreating an oil shale formation may include providing to a computationalsystem at least one set of operating conditions of an in situ systembeing used to apply heat to a formation. The in situ system may includeat least one heat source. The method may further include providing tothe computational system at least one desired parameter for the in situsystem. The computational system may be used to determine at least oneadditional operating condition of the formation to achieve the desiredparameter.

[0072] In an embodiment, operating conditions may be determined bymeasuring at least one property of the formation. At least one measuredproperty may be input into a computer executable program. At least oneproperty of formation fluids selected to be produced from the formationmay also be input into the computer executable program. The program maybe operable to determine a set of operating conditions from at least theone or more measured properties. The program may also determine the setof operating conditions from at least one property of the selectedformation fluids. The determined set of operating conditions mayincrease production of selected formation fluids from the formation.

[0073] In some embodiments, a property of the formation and an operatingcondition used in the in situ process may be provided to a computersystem to model the in situ process to determine a processcharacteristic.

[0074] In an embodiment, a heat input rate for an in situ process fromtwo or more heat sources may be simulated on a computer system. Adesired parameter of the in situ process may be provided to thesimulation. The heat input rate from the heat sources may be controlledto achieve the desired parameter.

[0075] Alternatively, a heat input property may be provided to acomputer system to assess heat injection rate data using a simulation.In addition, a property of the formation may be provided to the computersystem. The property and the heat injection rate data may be utilized bya second simulation to determine a process characteristic for the insitu process as a function of time.

[0076] Values for the model parameters may be adjusted using processcharacteristics from a series of simulations. The model parameters maybe adjusted such that the simulated process characteristics correspondto process characteristics in situ. After the model parameters have beenmodified to correspond to the in situ process, a process characteristicor a set of process characteristics based on the modified modelparameters may be determined. In certain embodiments, multiplesimulations may be run such that the simulated process characteristicscorrespond to the process characteristics in situ.

[0077] In some embodiments, operating conditions may be supplied to asimulation to assess a process characteristic. Additionally, a desiredvalue of a process characteristic for the in situ process may beprovided to the simulation to assess an operating condition that yieldsthe desired value.

[0078] In certain embodiments, databases in memory on a computer may beused to store relationships between model parameters, properties of theformation, operating conditions, process characteristics, desiredparameters, etc. These databases may be accessed by the simulations toobtain inputs. For example, after desired values of processcharacteristics are provided to simulations, an operating condition maybe assessed to achieve the desired values using these databases.

[0079] In some embodiments, computer systems may utilize inputs in asimulation to assess information about the in situ process. In someembodiments, the assessed information may be used to operate the in situprocess. Alternatively, the assessed information and a desired parametermay be provided to a second simulation to obtain information. Thisobtained information may be used to operate the in situ process.

[0080] In an embodiment, a method of modeling may include simulating oneor more stages of the in situ process. Operating conditions from the oneor more stages may be provided to a simulation to assess a processcharacteristic of the one or more stages.

[0081] In an embodiment, operating conditions may be assessed bymeasuring at least one property of the formation. At least the measuredproperties may be input into a computer executable program. At least oneproperty of formation fluids selected to be produced from the formationmay also be input into the computer executable program. The program maybe operable to assess a set of operating conditions from at least theone or more measured properties. The program may also determine the setof operating conditions from at least one property of the selectedformation fluids. The assessed set of operating conditions may increaseproduction of selected formation fluids from the formation.

[0082] In one embodiment, a method for controlling an in situ system oftreating an oil shale formation may include monitoring at least oneacoustic event within the formation using at least one acoustic detectorplaced within a wellbore in the formation. At least one acoustic eventmay be recorded with an acoustic monitoring system. The method may alsoinclude analyzing the at least one acoustic event to determine at leastone property of the formation. The in situ system may be controlledbased on the analysis of the at least one acoustic event.

[0083] An embodiment of a method of determining a heating rate fortreating an oil shale formation in situ may include conducting anexperiment at a relatively constant heating rate. The results of theexperiment may be used to determine a heating rate for treating theformation in situ. The determined heating rate may be used to determinea well spacing in the formation.

[0084] In an embodiment, a method of predicting characteristics of aformation fluid may include determining an isothermal heatingtemperature that corresponds to a selected heating rate for theformation. The determined isothermal temperature may be used in anexperiment to determine at least one product characteristic of theformation fluid produced from the formation for the selected heatingrate. Certain embodiments may include altering a composition offormation fluids produced from an oil shale formation by altering alocation of a production well with respect to a heater well. Forexample, a production well may be located with respect to a heater wellsuch that a non-condensable gas fraction of produced hydrocarbon fluidsmay be larger than a condensable gas fraction of the producedhydrocarbon fluids.

[0085] Condensable hydrocarbons produced from the formation willtypically include paraffins, cycloalkanes, mono-aromatics, anddi-aromatics as major components. Such condensable hydrocarbons may alsoinclude other components such as tri-aromatics, etc.

[0086] In certain embodiments, a majority of the hydrocarbons inproduced fluid may have a carbon number of less than approximately 25.Alternatively, less than about 15 weight % of the hydrocarbons in thefluid may have a carbon number greater than approximately 25. In otherembodiments, fluid produced may have a weight ratio of hydrocarbonshaving carbon numbers from 2 through 4, to methane, of greater thanapproximately 1 (e.g., for oil shale). The non-condensable hydrocarbonsmay include, but are not limited to, hydrocarbons having carbon numbersless than 5.

[0087] In certain embodiments, the API gravity of the hydrocarbons inproduced fluid may be approximately 25 or above (e.g., 30, 40, 50,etc.). In certain embodiments, the hydrogen to carbon atomic ratio inproduced fluid may be at least approximately 1.7 (e.g., 1.8, 1.9, etc.).

[0088] In certain embodiments, fluid produced from a formation mayinclude oxygenated hydrocarbons. In an example, the condensablehydrocarbons may include an amount of oxygenated hydrocarbons greaterthan about 5 weight % of the condensable hydrocarbons.

[0089] Condensable hydrocarbons of a produced fluid may also includeolefins. For example, the olefin content of the condensable hydrocarbonsmay be from about 0.1 weight % to about 15 weight %. Alternatively, theolefin content of the condensable hydrocarbons 5 may be from about 0.1weight % to about 2.5 weight % or, in some embodiments, less than about5 weight %.

[0090] Non-condensable hydrocarbons of a produced fluid may also includeolefins. For example, the olefin content of the non-condensablehydrocarbons may be gauged using the ethene/ethane molar ratio. Incertain embodiments, the ethene/ethane molar ratio may range from about0.001 to about 0.15.

[0091] Fluid produced from the formation may include aromatic compounds.For example, the condensable hydrocarbons may include an amount ofaromatic compounds greater than about 20 weight % or about 25 weight %of the condensable hydrocarbons. The condensable hydrocarbons may alsoinclude relatively low amounts of compounds with more than two rings inthem (e.g., tri-aromatics or above). For example, the condensablehydrocarbons may include less than about 1 weight %, 2 weight %, orabout 5 weight % of tri-aromatics or above in the condensablehydrocarbons.

[0092] In particular, in certain embodiments, asphaltenes (i.e., largemulti-ring aromatics that are substantially insoluble in hydrocarbons)make up less than about 0.1 weight % of the condensable hydrocarbons.For example, the condensable hydrocarbons may include an asphaltenecomponent of from about 0.0 weight % to about 0.1 weight % or, in someembodiments, less than about 0.3 weight %.

[0093] Condensable hydrocarbons of a produced fluid may also includerelatively large amounts of cycloalkanes. For example, the condensablehydrocarbons may include a cycloalkane component of up to 30 weight %(e.g., from about 5 weight % to about 30 weight %) of the condensablehydrocarbons.

[0094] In certain embodiments, the condensable hydrocarbons of the fluidproduced from a formation may include compounds containing nitrogen. Forexample, less than about 1 weight % (when calculated on an elementalbasis) of the condensable hydrocarbons is nitrogen (e.g., typically thenitrogen is in nitrogen containing compounds such as pyridines, amines,amides, etc.).

[0095] In certain embodiments, the condensable hydrocarbons of the fluidproduced from a formation may include compounds containing oxygen. Forexample, in certain embodiments (e.g., for oil shale), less than about 1weight % (when calculated on an elemental basis) of the condensablehydrocarbons is oxygen (e.g., typically the oxygen is in oxygencontaining compounds such as phenols, substituted phenols, ketones,etc.). In some instances, certain compounds containing oxygen (e.g.,phenols) may be valuable and, as such, may be economically separatedfrom the produced fluid.

[0096] In certain embodiments, the condensable hydrocarbons of the fluidproduced from a formation may include compounds containing sulfur. Forexample, less than about 1 weight % (when calculated on an elementalbasis) of the condensable hydrocarbons is sulfur (e.g., typically thesulfur is in sulfur containing compounds such as thiophenes, mercaptans,etc.).

[0097] Furthermore, the fluid produced from the formation may includeammonia (typically the ammonia condenses with the water, if any,produced from the formation). For example, the fluid produced from theformation may in certain embodiments include about 0.05 weight % or moreof ammonia. Certain formations may produce larger amounts of ammonia(e.g., up to about 10 weight % of the total fluid produced may beammonia).

[0098] Furthermore, a produced fluid from the formation may also includemolecular hydrogen (H₂), water, carbon dioxide, hydrogen sulfide, etc.For example, the fluid may include a H₂ content between about 10 volume% and about 80 volume % of the non-condensable hydrocarbons.

[0099] Certain embodiments may include heating to yield at least about15 weight % of a total organic carbon content of at least some of theoil shale formation into formation fluids.

[0100] In an embodiment, an in situ conversion process for treating anoil shale formation may include providing heat to a section of theformation to yield greater than about 60 weight % of the potentialhydrocarbon products and hydrogen, as measured by the Fischer Assay.

[0101] In certain embodiments, heating of the selected section of theformation may be controlled to pyrolyze at least about 20 weight % (orin some embodiments about 25 weight %) of the hydrocarbons within theselected section of the formation.

[0102] Formation fluids produced from a section of the formation maycontain one or more components that may be separated from the formationfluids. In addition, conditions within the formation may be controlledto increase production of a desired component.

[0103] In certain embodiments, a method of converting pyrolysis fluidsinto olefins may include converting formation fluids into olefins. Anembodiment may include separating olefins from fluids produced from aformation.

[0104] In an embodiment, a method of enhancing phenol production from anin situ oil shale formation may include controlling at least onecondition within at least a portion of the formation to enhanceproduction of phenols in formation fluid. In other embodiments,production of phenols from an oil shale formation may be controlled byconverting at least a portion of formation fluid into phenols.Furthermore, phenols may be separated from fluids produced from an insitu oil shale formation.

[0105] An embodiment of a method of enhancing BTEX compounds (i.e.,benzene, toluene, ethylbenzene, and xylene compounds) produced in situin an oil shale formation may include controlling at least one conditionwithin a portion of the formation to enhance production of BTEXcompounds in formation fluid. In another embodiment, a method mayinclude separating at least a portion of the BTEX compounds from theformation fluid. In addition, the BTEX compounds may be separated fromthe formation fluids after the formation fluids are produced. In otherembodiments, at least a portion of the produced formation fluids may beconverted into BTEX compounds.

[0106] In one embodiment, a method of enhancing naphthalene productionfrom an in situ oil shale formation may include controlling at least onecondition within at least a portion of the formation to enhanceproduction of naphthalene in formation fluid. In another embodiment,naphthalene may be separated from produced formation fluids.

[0107] Certain embodiments of a method of enhancing anthraceneproduction from an in situ oil shale formation may include controllingat least one condition within at least a portion of the formation toenhance production of anthracene in formation fluid. In an embodiment,anthracene may be separated from produced formation fluids.

[0108] In one embodiment, a method of separating ammonia from fluidsproduced from an in situ oil shale formation may include separating atleast a portion of the ammonia from the produced fluid. Furthermore, anembodiment of a method of generating ammonia from fluids produced from aformation may include hydrotreating at least a portion of the producedfluids to generate ammonia.

[0109] In an embodiment, a method of enhancing pyridines production froman in situ oil shale formation may include controlling at least onecondition within at least a portion of the formation to enhanceproduction of pyridines in formation fluid. Additionally, pyridines maybe separated from produced formation fluids.

[0110] In certain embodiments, a method of selecting an oil shaleformation to be treated in situ such that production of pyridines isenhanced may include examining pyridines concentrations in a pluralityof samples from oil shale formations. The method may further includeselecting a formation for treatment at least partially based on thepyridines concentrations. Consequently, the production of pyridines tobe produced from the formation may be enhanced.

[0111] In an embodiment, a method of enhancing pyrroles production froman in situ oil shale formation may include controlling at least onecondition within at least a portion of the formation to enhanceproduction of pyrroles in formation fluid. In addition, pyrroles may beseparated from produced formation fluids.

[0112] In certain embodiments, an oil shale formation to be treated insitu may be selected such that production of pyrroles is enhanced. Themethod may include examining pyrroles concentrations in a plurality ofsamples from oil shale formations. The formation may be selected fortreatment at least partially based on the pyrroles concentrations,thereby enhancing the production of pyrroles to be produced from suchformation.

[0113] In one embodiment, thiophenes production from an in situ oilshale formation may be enhanced by controlling at least one conditionwithin at least a portion of the formation to enhance production ofthiophenes in formation fluid. Additionally, the thiophenes may beseparated from produced formation fluids.

[0114] An embodiment of a method of selecting an oil shale formation tobe treated in situ such that production of thiophenes is enhanced mayinclude examining thiophenes concentrations in a plurality of samplesfrom oil shale formations. The method may further include selecting aformation for treatment at least partially based on the thiophenesconcentrations, thereby enhancing the production of thiophenes from suchformations.

[0115] Certain embodiments may include providing a reducing agent to atleast a portion of the formation. A reducing agent provided to a portionof the formation during heating may increase production of selectedformation fluids. A reducing agent may include, but is not limited to,molecular hydrogen. For example, pyrolyzing at least some hydrocarbonsin an oil shale formation may include forming hydrocarbon fragments.Such hydrocarbon fragments may react with each other and other compoundspresent in the formation. Reaction of these hydrocarbon fragments mayincrease production of olefin and aromatic compounds from the formation.Therefore, a reducing agent provided to the formation may react withhydrocarbon fragments to form selected products and/or inhibit theproduction of non-selected products.

[0116] In an embodiment, a hydrogenation reaction between a reducingagent provided to an oil shale formation and at least some of thehydrocarbons within the formation may generate heat. The generated heatmay be allowed to transfer such that at least a portion of the formationmay be heated. A reducing agent such as molecular hydrogen may also beautogenously generated within a portion of an oil shale formation duringan in situ conversion process for hydrocarbons. The autogenouslygenerated molecular hydrogen may hydrogenate formation fluids within theformation. Allowing formation waters to contact hot carbon in the spentformation may generate molecular hydrogen. Cracking an injectedhydrocarbon fluid may also generate molecular hydrogen.

[0117] Certain embodiments may also include providing a fluid producedin a first portion of an oil shale formation to a second portion of theformation. A fluid produced in a first portion of an oil shale formationmay be used to produce a reducing environment in a second portion of theformation. For example, molecular hydrogen generated in a first portionof a formation may be provided to a second portion of the formation.Alternatively, at least a portion of formation fluids produced from afirst portion of the formation may be provided to a second portion ofthe formation to provide a reducing environment within the secondportion.

[0118] In an embodiment, a method for hydrotreating a compound in aheated formation in situ may include controlling the H₂ partial pressurein a selected section of the formation, such that sufficient H₂ may bepresent in the selected section of the formation for hydrotreating. Themethod may further include providing a compound for hydrotreating to atleast the selected section of the formation and producing a mixture fromthe formation that includes at least some of the hydrotreated compound.

[0119] Certain embodiments may include controlling heat provided to atleast a portion of the formation such that a thermal conductivity of theportion may be increased to greater than about 0.5 W/(m ° C.) or, insome embodiments, greater than about 0.6 W/(m ° C.).

[0120] In certain embodiments, a mass of at least a portion of theformation may be reduced due, for example, to the production offormation fluids from the formation. As such, a permeability andporosity of at least a portion of the formation may increase. Inaddition, removing water during the heating may also increase thepermeability and porosity of at least a portion of the formation.

[0121] Certain embodiments may include increasing a permeability of atleast a portion of an oil shale formation to greater than about 0.01,0.1, 1, 10, 20, and/or 50 darcy. In addition, certain embodiments mayinclude substantially uniformly increasing a permeability of at least aportion of an oil shale formation. Some embodiments may includeincreasing a porosity of at least a portion of an oil shale formationsubstantially uniformly.

[0122] Hydrocarbon fluids produced from the formation may vary dependingon conditions within the formation. For example, a heating rate of aselected pyrolyzation section may be controlled to increase theproduction of selected products. In addition, pressure within theformation may be controlled to vary the composition of the producedfluids.

[0123] In an embodiment, heat is provided from a first set of heatsources to a first section of an oil shale formation to pyrolyze aportion of the hydrocarbons in the first section. Heat may also beprovided from a second set of heat sources to a second section of theformation. The heat may reduce the viscosity of hydrocarbons in thesecond section so that a portion of the hydrocarbons in the secondsection are able to move. A portion of the hydrocarbons from the secondsection may be induced to flow into the first section. A mixture ofhydrocarbons may be produced from the formation. The produced mixturemay include at least some pyrolyzed hydrocarbons.

[0124] In an embodiment, heat is provided from heat sources to a portionof an oil shale formation. The heat may transfer from the heat sourcesto a selected section of the formation to decrease a viscosity ofhydrocarbons within the selected section. A gas may be provided to theselected section of the formation. The gas may displace hydrocarbonsfrom the selected section towards a production well or production wells.A mixture of hydrocarbons may be produced from the selected sectionthrough the production well or production wells.

[0125] In some embodiments, energy supplied to a heat source or to asection of a heat source may be selectively limited to controltemperature and to inhibit coke formation at or near the heat source. Insome embodiments, a mixture of hydrocarbons may be produced throughportions of a heat source that are operated to inhibit coke formation.

[0126] In certain embodiments, a quality of a produced mixture may becontrolled by varying a location for producing the mixture. The locationof production may be varied by varying the depth in the formation fromwhich fluid is produced relative an overburden or underburden. Thelocation of production may also be varied by varying which productionwells are used to produce fluid. In some embodiments, the productionwells used to remove fluid may be chosen based on a distance of theproduction wells from activated heat sources.

[0127] In some embodiments, heat may be provided to a selected sectionof an oil shale formation to pyrolyze some hydrocarbons in a lowerportion of the formation. A mixture of hydrocarbons may be produced froman upper portion of the formation. The mixture of hydrocarbons mayinclude at least some pyrolyzed hydrocarbons from the lower portion ofthe formation.

[0128] In certain embodiments, a production rate of fluid from theformation may be controlled to adjust an average time that hydrocarbonsare in, or flowing into, a pyrolysis zone or exposed to pyrolysistemperatures. Controlling the production rate may allow for productionof a large quantity of hydrocarbons of a desired quality from theformation.

[0129] A heated formation may also be used to produce synthesis gas.Synthesis gas may be produced from the formation prior to or subsequentto producing a formation fluid from the formation. For example,synthesis gas generation may be commenced before and/or after formationfluid production decreases to an uneconomical level. Heat provided topyrolyze hydrocarbons within the formation may also be used to generatesynthesis gas. For example, if a portion of the formation is at atemperature from approximately 270° C. to approximately 375° C. (or 400°C. in some embodiments) after pyrolyzation, then less additional heat isgenerally required to heat such portion to a temperature sufficient tosupport synthesis gas generation.

[0130] In certain embodiments, synthesis gas is produced afterproduction of pyrolysis fluids. For example, after pyrolysis of aportion of a formation, synthesis gas may be produced from carbon and/orhydrocarbons remaining within the formation. Pyrolysis of the portionmay produce a relatively high, substantially uniform permeabilitythroughout the portion. Such a relatively high, substantially uniformpermeability may allow generation of synthesis gas from a significantportion of the formation at relatively low pressures. The portion mayalso have a large surface area and/or surface area/volume. The largesurface area may allow synthesis gas producing reactions to besubstantially at equilibrium conditions during synthesis gas generation.The relatively high, substantially uniform permeability may result in arelatively high recovery efficiency of synthesis gas, as compared tosynthesis gas generation in an oil shale formation that has not been sotreated.

[0131] Pyrolysis of at least some hydrocarbons may in some embodimentsconvert about 15 weight % or more of the carbon initially available.Synthesis gas generation may convert approximately up to an additional80 weight % or more of carbon initially available within the portion. Insitu production of synthesis gas from an oil shale formation may allowconversion of larger amounts of carbon initially available within theportion. The amount of conversion achieved may, in some embodiments, belimited by subsidence concerns.

[0132] Certain embodiments may include providing heat from one or moreheat sources to heat the formation to a temperature sufficient to allowsynthesis gas generation (e.g., in a range of approximately 400° C. toapproximately 1200° C. or higher). At a lower end of the temperaturerange, generated synthesis gas may have a high hydrogen (H₂) to carbonmonoxide (CO) ratio. At an upper end of the temperature range, generatedsynthesis gas may include mostly H₂ and CO in lower ratios (e.g.,approximately a 1:1 ratio).

[0133] Heat sources for synthesis gas production may include any of theheat sources as described in any of the embodiments set forth herein.Alternatively, heating may include transferring heat from a heattransfer fluid (e.g., steam or combustion products from a burner)flowing within a plurality of wellbores within the formation.

[0134] A synthesis gas generating fluid (e.g., liquid water, steam,carbon dioxide, air, oxygen, hydrocarbons, and mixtures thereof) may beprovided to the formation. For example, the synthesis gas generatingfluid mixture may include steam and oxygen. In an embodiment, asynthesis gas generating fluid may include aqueous fluid produced bypyrolysis of at least some hydrocarbons within one or more otherportions of the formation. Providing the synthesis gas generating fluidmay alternatively include raising a water table of the formation toallow water to flow into it. Synthesis gas generating fluid may also beprovided through at least one injection wellbore. The synthesis gasgenerating fluid will generally react with carbon in the formation toform H₂, water, methane, CO₂, and/or CO. A portion of the carbon dioxidemay react with carbon in the formation to generate carbon monoxide.Hydrocarbons such as ethane may be added to a synthesis gas generatingfluid. When introduced into the formation, the hydrocarbons may crack toform hydrogen and/or methane. The presence of methane in producedsynthesis gas may increase the heating value of the produced synthesisgas.

[0135] Synthesis gas generation is, in some embodiments, an endothermicprocess. Additional heat may be added to the formation during synthesisgas generation to maintain a high temperature within the formation. Theheat may be added from heater wells and/or from oxidizing carbon and/orhydrocarbons within the formation.

[0136] In an embodiment, an oxidant may be added to a synthesis gasgenerating fluid. The oxidant may include, but is not limited to, air,oxygen enriched air, oxygen, hydrogen peroxide, other oxidizing fluids,or combinations thereof. The oxidant may react with carbon within theformation to exothermically generate heat. Reaction of an oxidant withcarbon in the formation may result in production of CO₂ and/or CO.Introduction of an oxidant to react with carbon in the formation mayeconomically allow raising the formation temperature high enough toresult in generation of significant quantities of H₂ and CO fromhydrocarbons within the formation. Synthesis gas generation may be via abatch process or a continuous process.

[0137] Synthesis gas may be produced from the formation through one ormore producer wells that include one or more heat sources. Such heatsources may operate to promote production of the synthesis gas with adesired composition.

[0138] Certain embodiments may include monitoring a composition of theproduced synthesis gas and then controlling heating and/or controllinginput of the synthesis gas generating fluid to maintain the compositionof the produced synthesis gas within a desired range. For example, insome embodiments (e.g., such as when the synthesis gas will be used as afeedstock for a Fischer-Tropsch process), a desired composition of theproduced synthesis gas may have a ratio of hydrogen to carbon monoxideof about 1.8:1 to 2.2:1 (e.g., about 2:1 or about 2.1:1). In someembodiments (such as when the synthesis gas will be used as a feedstockto make methanol), such ratio may be about 3:1 (e.g., about 2.8:1 to3.2:1).

[0139] Certain embodiments may include blending a first synthesis gaswith a second synthesis gas to produce synthesis gas of a desiredcomposition. The first and the second synthesis gases may be producedfrom different portions of the formation.

[0140] Synthesis gases may be converted to heavier condensablehydrocarbons. For example, a Fischer-Tropsch hydrocarbon synthesisprocess may convert synthesis gas to branched and unbranched paraffins.Paraffins produced from the Fischer-Tropsch process may be used toproduce other products such as diesel, jet fuel, and naphtha products.The produced synthesis gas may also be used in a catalytic methanationprocess to produce methane. Alternatively, the produced synthesis gasmay be used for production of methanol, gasoline and diesel fuel,ammonia, and middle distillates. Produced synthesis gas may be used toheat the formation as a combustion fuel. Hydrogen in produced synthesisgas may be used to upgrade oil.

[0141] Synthesis gas may also be used for other purposes. Synthesis gasmay be combusted as fuel. Synthesis gas may also be used forsynthesizing a wide range of organic and/or inorganic compounds, such ashydrocarbons and ammonia. Synthesis gas may be used to generateelectricity by combusting it as a fuel, by reducing the pressure of thesynthesis gas in turbines, and/or using the temperature of the synthesisgas to make steam (and then run turbines). Synthesis gas may also beused in an energy generation unit such as a molten carbonate fuel cell,a solid oxide fuel cell, or other type of fuel cell.

[0142] Certain embodiments may include separating a fuel cell feedstream from fluids produced from pyrolysis of at least some of thehydrocarbons within a formation. The fuel cell feed stream may includeH₂, hydrocarbons, and/or carbon monoxide. In addition, certainembodiments may include directing the fuel cell feed stream to a fuelcell to produce electricity. The electricity generated from thesynthesis gas or the pyrolyzation fluids in the fuel cell may powerelectric heaters, which may heat at least a portion of the formation.Certain embodiments may include separating carbon dioxide from a fluidexiting the fuel cell. Carbon dioxide produced from a fuel cell or aformation may be used for a variety of purposes.

[0143] In certain embodiments, synthesis gas produced from a heatedformation may be transferred to an additional area of the formation andstored within the additional area of the formation for a length of time.The conditions of the additional area of the formation may inhibitreaction of the synthesis gas. The synthesis gas may be produced fromthe additional area of the formation at a later time.

[0144] In some embodiments, treating a formation may include injectingfluids into the formation. The method may include providing heat to theformation, allowing the heat to transfer to a selected section of theformation, injecting a fluid into the selected section, and producinganother fluid from the formation. Additional heat may be provided to atleast a portion of the formation, and the additional heat may be allowedto transfer from at least the portion to the selected section of theformation. At least some hydrocarbons may be pyrolyzed within theselected section and a mixture may be produced from the formation.Another embodiment may include leaving a section of the formationproximate the selected section substantially unleached. The unleachedsection may inhibit the flow of water into the selected section.

[0145] In an embodiment, heat may be provided to the formation. The heatmay be allowed to transfer to a selected section of the formation suchthat dissociation of carbonate minerals is inhibited. At least somehydrocarbons may be pyrolyzed within the selected section and a mixtureproduced from the formation. The method may further include reducing atemperature of the selected section and injecting a fluid into theselected section. Another fluid may be produced from the formation.Alternatively, subsequent to providing heat and allowing heat totransfer, a method may include injecting a fluid into the selectedsection and producing another fluid from the formation. Similarly, amethod may include injecting a fluid into the selected section andpyrolyzing at least some hydrocarbons within the selected section of theformation after providing heat and allowing heat to transfer to theselected section.

[0146] In an embodiment that includes injecting fluids, a method oftreating a formation may include providing heat from one or more heatsources and allowing the heat to transfer to a selected section of theformation such that a temperature of the selected section is less thanabout a temperature at which nahcolite dissociates. A fluid may beinjected into the selected section and another fluid may be producedfrom the formation. The method may further include providing additionalheat to the formation, allowing the additional heat to transfer to theselected section of the formation, and pyrolyzing at least somehydrocarbons within the selected section. A mixture may then be producedfrom the formation.

[0147] Certain embodiments that include injecting fluids may alsoinclude controlling the heating of the formation. A method may includeproviding heat to the formation, controlling the heat such that aselected section is at a first temperature, injecting a fluid into theselected section, and producing another fluid from the formation. Themethod may further include controlling the heat such that the selectedsection is at a second temperature that is greater than the firsttemperature. Heat may be allowed to transfer from the selected section,and at least some hydrocarbons may be pyrolyzed within the selectedsection of the formation. A mixture may be produced from the formation.

[0148] A further embodiment that includes injecting fluids may includeproviding heat to a formation, allowing the heat to transfer to aselected section of the formation, injecting a first fluid into theselected section, and producing a second fluid from the formation. Themethod may further include providing additional heat, allowing theadditional heat to transfer to the selected section of the formation,pyrolyzing at least some hydrocarbons within the selected section of theformation, and producing a mixture from the formation. In addition, atemperature of the selected section may be reduced and a third fluid maybe injected into the selected section. A fourth fluid may be producedfrom the formation.

[0149] In some embodiments, migration of fluids into and/or out of atreatment area may be inhibited. Inhibition of migration of fluids mayoccur before, during, and/or after an in situ treatment process. Forexample, migration of fluids may be inhibited while heat is providedfrom one or more heat sources to at least a portion of the treatmentarea. The heat may be allowed to transfer to at least a portion of thetreatment area. Fluids may be produced from the treatment area.

[0150] Barriers may be used to inhibit migration of fluids into and/orout of a treatment area in a formation. Barriers may include, but arenot limited to naturally occurring portions (e.g., overburden and/orunderburden), frozen barrier zones, low temperature barrier zones, groutwalls, sulfur wells, dewatering wells, and/or injection wells. Barriersmay define the treatment area. Alternatively, barriers may be providedto a portion of the treatment area.

[0151] In an embodiment, a method of treating an oil shale formation insitu may include providing a refrigerant to a plurality of barrier wellsto form a low temperature barrier zone. The method may further includeestablishing a low temperature barrier zone. In some embodiments, thetemperature within the low temperature barrier zone may be lowered toinhibit the flow of water into or out of at least a portion of atreatment area in the formation.

[0152] Certain embodiments of treating an oil shale formation in situmay include providing a refrigerant to a plurality of barrier wells toform a frozen barrier zone. The frozen barrier zone may inhibitmigration of fluids into and/or out of the treatment area. In certainembodiments, a portion of the treatment area is below a water table ofthe formation. In addition, the method may include controlling pressureto maintain a fluid pressure within the treatment area above ahydrostatic pressure of the formation and producing a mixture of fluidsfrom the formation.

[0153] Barriers may be provided to a portion of the formation prior to,during, and after providing heat from one or more heat sources to thetreatment area. For example, a barrier may be provided to a portion ofthe formation that has previously undergone a conversion process.

[0154] Fluid may be introduced to a portion of the formation that haspreviously undergone an in situ conversion process. The fluid may beproduced from the formation in a mixture, which may contain additionalfluids present in the formation. In some embodiments, the producedmixture may be provided to an energy producing unit.

[0155] In some embodiments, one or more conditions in a selected sectionmay be controlled during an in situ conversion process to inhibitformation of carbon dioxide. Conditions may be controlled to producefluids having a carbon dioxide emission level that is less than aselected carbon dioxide level. For example, heat provided to theformation may be controlled to inhibit generation of carbon dioxide,while increasing production of molecular hydrogen.

[0156] In a similar manner, a method for producing methane from an oilshale formation in situ while minimizing production of CO₂ may includecontrolling the heat from the one or more heat sources to enhanceproduction of methane in the produced mixture and generating heat via atleast one or more of the heat sources in a manner that minimizes CO₂production. The methane may further include controlling a temperatureproximate the production wellbore at or above a decompositiontemperature of ethane.

[0157] In certain embodiments, a method for producing products from aheated formation may include controlling a condition within a selectedsection of the formation to produce a mixture having a carbon dioxideemission level below a selected baseline carbon dioxide emission level.In some embodiments, the mixture may be blended with a fluid to generatea product having a carbon dioxide emission level below the baseline.

[0158] In an embodiment, a method for producing methane from a heatedformation in situ may include providing heat from one or more heatsources to at least one portion of the formation and allowing the heatto transfer to a selected section of the formation. The method mayfurther include providing hydrocarbon compounds to at least the selectedsection of the formation and producing a mixture including methane fromthe hydrocarbons in the formation.

[0159] One embodiment of a method for producing hydrocarbons in a heatedformation may include forming a temperature gradient in at least aportion of a selected section of the heated formation and providing ahydrocarbon mixture to at least the selected section of the formation. Amixture may then be produced from a production well.

[0160] In certain embodiments, a method for upgrading hydrocarbons in aheated formation may include providing hydrocarbons to a selectedsection of the heated formation and allowing the hydrocarbons to crackin the heated formation. The cracked hydrocarbons may be a higher gradethan the provided hydrocarbons. The upgraded hydrocarbons may beproduced from the formation.

[0161] Cooling a portion of the formation after an in situ conversionprocess may provide certain benefits, such as increasing the strength ofthe rock in the formation (thereby mitigating subsidence), increasingabsorptive capacity of the formation, etc.

[0162] In an embodiment, a portion of a formation that has beenpyrolyzed and/or subjected to synthesis gas generation may be allowed tocool or may be cooled to form a cooled, spent portion within theformation. For example, a heated portion of a formation may be allowedto cool by transference of heat to an adjacent portion of the formation.The transference of heat may occur naturally or may be forced by theintroduction of heat transfer fluids through the heated portion and intoa cooler portion of the formation.

[0163] In alternate embodiments, recovering thermal energy from a posttreatment oil shale formation may include injecting a heat recoveryfluid into a portion of the formation. Heat from the formation maytransfer to the heat recovery fluid. The heat recovery fluid may beproduced from the formation. For example, introducing water to a portionof the formation may cool the portion. Water introduced into the portionmay be removed from the formation as steam. The removed steam or hotwater may be injected into a hot portion of the formation to createsynthesis gas

[0164] In an embodiment, hydrocarbons may be recovered from a posttreatment oil shale formation by injecting a heat recovery fluid into aportion of the formation. Heat may vaporize at least some of the heatrecovery fluid and at least some hydrocarbons in the formation. Aportion of the vaporized recovery fluid and the vaporized hydrocarbonsmay be produced from the formation.

[0165] In certain embodiments, fluids in the formation may be removedfrom a post treatment oil shale formation by injecting a heat recoveryfluid into a portion of the formation. Heat may transfer to the heatrecovery fluid and a portion of the fluid may be produced from theformation. The heat recovery fluid produced from the formation mayinclude at least some of the fluids in the formation.

[0166] In one embodiment, a method of recovering excess heat from aheated formation may include providing a product stream to the heatedformation, such that heat transfers from the heated formation to theproduct stream. The method may further include producing the productstream from the heated formation and directing the product stream to aprocessing unit. The heat of the product stream may then be transferredto the processing unit. In an alternate method for recovering excessheat from a heated formation the heated product stream may be directedto another formation, such that heat transfers from the product streamto the other formation.

[0167] In one embodiment, a method of utilizing heat of a heatedformation may include placing a conduit in the formation, such thatconduit input may be located separately from conduit output. The conduitmay be heated by the heated formation to produce a region of reaction inat least a portion of the conduit. The method may further includedirecting a material through the conduit to the region of reaction. Thematerial may undergo change in the region of reaction. A product may beproduced from the conduit.

[0168] An embodiment of a method of utilizing heat of a heated formationmay include providing heat from one or more heat sources to at least oneportion of the formation and allowing the heat to transfer to a regionof reaction in the formation. Material may be directed to the region ofreaction and allowed to react in the region of reaction. A mixture maythen be produced from the formation.

[0169] In an embodiment, a portion of an oil shale formation may be usedto store and/or sequester materials (e.g., formation fluids, carbondioxide). The conditions within the portion of the formation may inhibitreactions of the materials. Materials may be may be stored in theportion for a length of time. In addition, materials may be producedfrom the portion at a later time. Materials stored within the portionmay have been previously produced from the portion of the formation,and/or another portion of the formation.

[0170] After an in situ conversion process has been completed in aportion of the formation, fluid may be sequestered within the formation.In some embodiments, to store a significant amount of fluid within theformation, a temperature of the formation will often need to be lessthan about 100° C. Water may be introduced into at least a portion ofthe formation to generate steam and reduce a temperature of theformation. The steam may be removed from the formation. The steam may beutilized for various purposes, including, but not limited to, heatinganother portion of the formation, generating synthesis gas in anadjacent portion of the formation, generating electricity, and/or as asteam flood in a oil reservoir. After the formation has cooled, fluid(e.g., carbon dioxide) may be pressurized and sequestered in theformation. Sequestering fluid within the formation may result in asignificant reduction or elimination of fluid that is released to theenvironment due to operation of the in situ conversion process.

[0171] In alternate embodiments, carbon dioxide may be injected underpressure into the portion of the formation. The injected carbon dioxidemay adsorb onto hydrocarbons in the formation and/or reside in voidspaces such as pores in the formation. The carbon dioxide may begenerated during pyrolysis, synthesis gas generation, and/or extractionof useful energy. In some embodiments, carbon dioxide may be stored inrelatively deep oil shale formations and used to desorb methane.

[0172] In one embodiment, a method for sequestering carbon dioxide in aheated formation may include precipitating carbonate compounds fromcarbon dioxide provided to a portion of the formation. In someembodiments, the portion may have previously undergone an in situconversion process. Carbon dioxide and a fluid may be provided to theportion of the formation. The fluid may combine with carbon dioxide inthe portion to precipitate carbonate compounds.

[0173] In an alternate embodiment, methane may be recovered from an oilshale formations by providing heat to the formation. The heat may desorba substantial portion of the methane within the selected section of theformation. At least a portion of the methane may be produced from theformation.

[0174] In an embodiment, a method for purifying water in a spentformation may include providing water to the formation and filtering theprovided water in the formation. The filtered water may then be producedfrom the formation.

[0175] In an embodiment, treating an oil shale formation in situ mayinclude injecting a recovery fluid into the formation. Heat may beprovided from one or more heat sources to the formation. The heat maytransfer from one or more of the heat sources to a selected section ofthe formation and vaporize a substantial portion of recovery fluid in atleast a portion of the selected section. The heat from the heat sourcesand the vaporized recovery fluid may pyrolyze at least some hydrocarbonswithin the selected section. A gas mixture may be produced from theformation. The produced gas mixture may include hydrocarbons with anaverage API gravity greater than about 25°.

[0176] In certain embodiments, a method of shutting-in an in situtreatment process in an oil shale formation may include terminatingheating from one or more heat sources providing heat to a portion of theformation. A pressure may be monitored and controlled in at least aportion of the formation. The pressure may be maintained approximatelybelow a fracturing or breakthrough pressure of the formation.

[0177] One embodiment of a method of shutting-in an in situ treatmentprocess in an oil shale formation may include terminating heating fromone or more heat sources providing heat to a portion of the formation.Hydrocarbon vapor may be produced from the formation. At least a portionof the produced hydrocarbon vapor may be injected into a portion of astorage formation. The hydrocarbon vapor may be injected into arelatively high temperature formation. A substantial portion of injectedhydrocarbons may be converted to coke and H₂ in the relatively hightemperature formation. Alternatively, the hydrocarbon vapor may bestored in a depleted formation.

BRIEF DESCRIPTION OF THE DRAWINGS

[0178] Further advantages of the present invention may become apparentto those skilled in the art with the benefit of the following detaileddescription of the preferred embodiments and upon reference to theaccompanying drawings in which:

[0179]FIG. 1 depicts an illustration of stages of heating an oil shaleformation.

[0180]FIG. 2 depicts a diagram that presents several properties ofkerogen resources.

[0181]FIG. 3 depicts an embodiment of a heat source pattern.

[0182]FIG. 4 depicts an embodiment of a heater well.

[0183]FIG. 5 depicts an embodiment of heater well.

[0184]FIG. 6 depicts an embodiment of heater well.

[0185]FIG. 7 illustrates a schematic view of multiple heaters branchedfrom a single well in an oil shale formation.

[0186]FIG. 8 illustrates a schematic of an elevated view of multipleheaters branched from a single well in an oil shale formation.

[0187]FIG. 9 depicts an embodiment of heater wells located in an oilshale formation.

[0188]FIG. 10 depicts an embodiment of a pattern of heater wells in anoil shale formation.

[0189]FIG. 11 depicts a schematic representation of an embodiment of amagnetostatic drilling operation.

[0190]FIG. 12 depicts a schematic of a portion of a magnetic string.

[0191]FIG. 13 depicts an embodiment of a heated portion of an oil shaleformation.

[0192]FIG. 14 depicts an embodiment of superposition of heat in an oilshale formation.

[0193]FIG. 15 illustrates an embodiment of a production well placed inan oil shale formation.

[0194]FIG. 16 depicts an embodiment of a pattern of heat sources andproduction wells in an oil shale formation.

[0195]FIG. 17 depicts an embodiment of a pattern of heat sources and aproduction well in an oil shale formation.

[0196]FIG. 18 illustrates a computational system.

[0197]FIG. 19 depicts a block diagram of a computational system.

[0198]FIG. 20 illustrates a flow chart of an embodiment of acomputer-implemented method for treating a formation based on acharacteristic of the formation.

[0199]FIG. 21 illustrates a schematic of an embodiment used to controlan in situ conversion process in a formation.

[0200]FIG. 22 illustrates a flowchart of an embodiment of a method formodeling an in situ process for treating an oil shale formation using acomputer system.

[0201]FIG. 23 illustrates a plot of a porosity-permeabilityrelationship.

[0202]FIG. 24 illustrates a method for simulating heat transfer in aformation.

[0203]FIG. 25 illustrates a model for simulating a heat transfer rate ina formation.

[0204]FIG. 26 illustrates a flowchart of an embodiment of a method forusing a computer system to model an in situ conversion process.

[0205]FIG. 27 illustrates a flow chart of an embodiment of a method forcalibrating model parameters to match laboratory or field data for an insitu process.

[0206]FIG. 28 illustrates a flowchart of an embodiment of a method forcalibrating model parameters.

[0207]FIG. 29 illustrates a flow chart of an embodiment of a method forcalibrating model parameters for a second simulation method using asimulation method.

[0208]FIG. 30 illustrates a flow chart of an embodiment of a method fordesign and/or control of an in situ process.

[0209]FIG. 31 depicts a method of modeling one or more stages of atreatment process.

[0210]FIG. 32 illustrates a flow chart of an embodiment of method fordesigning and controlling an in situ process with a simulation method ona computer system.

[0211]FIG. 33 illustrates a model of a formation that may be used insimulations of deformation characteristics according to one embodiment.

[0212]FIG. 34 illustrates a schematic of a strip development accordingto one embodiment.

[0213]FIG. 35 depicts a schematic illustration of a treated portion thatmay be modeled with a simulation.

[0214]FIG. 36 depicts a horizontal cross section of a model of aformation for use by a simulation method according to one embodiment.

[0215]FIG. 37 illustrates a flow chart of an embodiment of a method formodeling deformation due to in situ treatment of an oil shale formation.

[0216]FIG. 38 depicts a profile of richness versus depth in a model ofan oil shale formation.

[0217]FIG. 39 illustrates a flow chart of an embodiment of a method forusing a computer system to design and control an in situ conversionprocess.

[0218]FIG. 40 illustrates a flow chart of an embodiment of a method fordetermining operating conditions to obtain desired deformationcharacteristics.

[0219]FIG. 41 illustrates the influence of operating pressure onsubsidence in a cylindrical model of a formation from a finite elementsimulation.

[0220]FIG. 42 illustrates influence of an untreated portion between twotreated portions.

[0221]FIG. 43 illustrates influence of an untreated portion between twotreated portions.

[0222]FIG. 44 represents shear deformation of a formation at thelocation of selected heat sources as a function of depth.

[0223]FIG. 45 illustrates a method for controlling an in situ processusing a computer system.

[0224]FIG. 46 illustrates a schematic of an embodiment for controllingan in situ process in a formation using a computer simulation method.

[0225]FIG. 47 illustrates several ways that information may betransmitted from an in situ process to a remote computer system.

[0226]FIG. 48 illustrates a schematic of an embodiment for controllingan in situ process in a formation using information.

[0227]FIG. 49 illustrates a schematic of an embodiment for controllingan in situ process in a formation using a simulation method and acomputer system.

[0228]FIG. 50 illustrates a flow chart of an embodiment of acomputer-implemented method for determining a selected overburdenthickness.

[0229]FIG. 51 illustrates a schematic diagram of a plan view of a zonebeing treated using an in situ conversion process.

[0230]FIG. 52 illustrates a schematic diagram of a cross-sectionalrepresentation of a zone being treated using an in situ conversionprocess.

[0231]FIG. 53 illustrates a flow chart of an embodiment of a method usedto monitor treatment of a formation.

[0232]FIG. 54 depicts an embodiment of a natural distributed combustorheat source.

[0233]FIG. 55 depicts an embodiment of a natural distributed combustorsystem for heating a formation.

[0234]FIG. 56 illustrates a cross-sectional representation of anembodiment of a natural distributed combustor having a second conduit.

[0235]FIG. 57 depicts a schematic representation of an embodiment of aheater well positioned within an oil shale formation.

[0236]FIG. 58 depicts a portion of an overburden of a formation with anatural distributed combustor heat source.

[0237]FIG. 59 depicts an embodiment of a natural distributed combustorheat source.

[0238]FIG. 60 depicts an embodiment of a natural distributed combustorheat source.

[0239]FIG. 61 depicts an embodiment of a natural distributed combustorsystem for heating a formation.

[0240]FIG. 62 depicts an embodiment of an insulated conductor heatsource.

[0241]FIG. 63 depicts an embodiment of a transition section of aninsulated conductor assembly.

[0242]FIG. 64 depicts an embodiment of an insulated conductor heatsource.

[0243]FIG. 65 depicts an embodiment of a wellhead of an insulatedconductor heat source.

[0244]FIG. 66 depicts an embodiment of a conductor-in-conduit heatsource in a formation.

[0245]FIG. 67 depicts an embodiment of three insulated conductor heatersplaced within a conduit.

[0246]FIG. 68 depicts an embodiment of a centralizer.

[0247]FIG. 69 depicts an embodiment of a centralizer.

[0248]FIG. 70 depicts an embodiment of a centralizer.

[0249]FIG. 71 depicts a cross-sectional representation of an embodimentof a removable conductor-in-conduit heat source.

[0250]FIG. 72 depicts an embodiment of a sliding connector.

[0251]FIG. 73 depicts an embodiment of a wellhead with aconductor-in-conduit heat source.

[0252]FIG. 74 illustrates a schematic of an embodiment of aconductor-in-conduit heater, wherein a portion of the heater is placedsubstantially horizontally within a formation.

[0253]FIG. 75 illustrates an enlarged view of an embodiment of ajunction of a conductor-in-conduit heater.

[0254]FIG. 76 illustrates a schematic of an embodiment of aconductor-in-conduit heater, wherein a portion of the heater is placedsubstantially horizontally within a formation.

[0255]FIG. 77 illustrates a schematic of an embodiment of aconductor-in-conduit heater, wherein a portion of the heater is placedsubstantially horizontally within a formation.

[0256]FIG. 78 illustrates a schematic of an embodiment of aconductor-in-conduit heater, wherein a portion of the heater is placedsubstantially horizontally within a formation.

[0257]FIG. 79 depicts a cross-sectional view of a portion of anembodiment of a cladding section coupled to a heater support and aconduit.

[0258]FIG. 80 illustrates a cross-sectional representation of anembodiment of a centralizer placed on a conductor.

[0259]FIG. 81 depicts a portion of an embodiment of aconductor-in-conduit heat source with a cutout view showing acentralizer on the conductor.

[0260]FIG. 82 depicts a cross-sectional representation of an embodimentof a centralizer.

[0261]FIG. 83 depicts a cross-sectional representation of an embodimentof a centralizer.

[0262]FIG. 84 depicts a top view of an embodiment of a centralizer.

[0263]FIG. 85 depicts a top view of an embodiment of a centralizer.

[0264]FIG. 86 depicts a cross-sectional representation of a portion ofan embodiment of a section of a conduit of a conduit-in-conductor heatsource with an insulation layer wrapped around the conductor.

[0265]FIG. 87 depicts a cross-sectional representation of an embodimentof a cladding section coupled to a low resistance conductor.

[0266]FIG. 88 depicts an embodiment of a conductor-in-conduit heatsource in a formation.

[0267]FIG. 89 depicts an embodiment for assembling aconductor-in-conduit heat source and installing the heat source in aformation.

[0268]FIG. 90 depicts an embodiment of a conductor-in-conduit heatsource to be installed in a formation.

[0269]FIG. 91 shows a cross-sectional representation of an end of atubular around which two pairs of diametrically opposite electrodes arearranged.

[0270]FIG. 92 depicts an embodiment of ends of two adjacent tubularsbefore forge welding.

[0271]FIG. 93 illustrates an end view of an embodiment of aconductor-in-conduit heat source heated by diametrically oppositeelectrodes.

[0272]FIG. 94 illustrates a cross-sectional representation of anembodiment of two conductor-in-conduit heat source sections before forgewelding.

[0273]FIG. 95 depicts an embodiment of heat sources installed in aformation.

[0274]FIG. 96 depicts an embodiment of a heat source in a formation.

[0275]FIG. 97 illustrates a cross-sectional representation of anembodiment of a heater with two oxidizers.

[0276]FIG. 98 illustrates a cross-sectional representation of anembodiment of a heater with an oxidizer and an electric heater.

[0277]FIG. 99 depicts a cross-sectional representation of an embodimentof a heater with an oxidizer and a flameless distributed combustorheater.

[0278]FIG. 100 illustrates a cross-sectional representation of anembodiment of a multilateral downhole combustor heater.

[0279]FIG. 101 illustrates a cross-sectional representation of anembodiment of a downhole combustor heater with two conduits.

[0280]FIG. 102 illustrates a cross-sectional representation of anembodiment of a downhole combustor.

[0281]FIG. 102A depicts an embodiment of a heat source for an oil shaleformation.

[0282]FIG. 103 depicts a representation of a portion of a piping layoutfor heating a formation using downhole combustors.

[0283]FIG. 104 depicts a schematic representation of an embodiment of aheater well positioned within an oil shale formation.

[0284]FIG. 105 depicts an embodiment of a heat source positioned in anoil shale formation.

[0285]FIG. 106 depicts a schematic representation of an embodiment of aheat source positioned in an oil shale formation.

[0286]FIG. 107 depicts an embodiment of a surface combustor heat source.

[0287]FIG. 108 depicts an embodiment of a conduit for a heat source witha portion of an inner conduit shown cut away to show a center tube.

[0288]FIG. 109 depicts an embodiment of a flameless combustor heatsource.

[0289]FIG. 110 illustrates a representation of an embodiment of anexpansion mechanism coupled to a heat source in an opening in aformation.

[0290]FIG. 111 illustrates a schematic of a thermocouple placed in awellbore.

[0291]FIG. 112 depicts a schematic of a well embodiment for usingpressure waves to measure temperature within a wellbore.

[0292]FIG. 113 illustrates a schematic of an embodiment that uses windto generate electricity to heat a formation.

[0293]FIG. 114 depicts an embodiment of a windmill for generatingelectricity.

[0294]FIG. 115 illustrates a schematic of an embodiment for using solarpower to heat a formation.

[0295]FIG. 116 depicts a cross-sectional representation of an embodimentfor treating a lean zone and a rich zone of a formation.

[0296]FIG. 117 depicts an embodiment of using pyrolysis water togenerate synthesis gas in a formation.

[0297]FIG. 118 depicts an embodiment of synthesis gas production in aformation.

[0298]FIG. 119 depicts an embodiment of continuous synthesis gasproduction in a formation.

[0299]FIG. 120 depicts an embodiment of batch synthesis gas productionin a formation.

[0300]FIG. 121 depicts an embodiment of producing energy with synthesisgas produced from an oil shale formation.

[0301]FIG. 122 depicts an embodiment of producing energy withpyrolyzation fluid produced from an oil shale formation.

[0302]FIG. 123 depicts an embodiment of synthesis gas production from aformation.

[0303]FIG. 124 depicts an embodiment of sequestration of carbon dioxideproduced during pyrolysis in an oil shale formation.

[0304]FIG. 125 depicts an embodiment of producing energy with synthesisgas produced from an oil shale formation.

[0305]FIG. 126 depicts an embodiment of a Fischer-Tropsch process usingsynthesis gas produced from an oil shale formation.

[0306]FIG. 127 depicts an embodiment of a Shell Middle Distillatesprocess using synthesis gas produced from an oil shale formation.

[0307]FIG. 128 depicts an embodiment of a catalytic methanation processusing synthesis gas produced from an oil shale formation.

[0308]FIG. 129 depicts an embodiment of production of ammonia and ureausing synthesis gas produced from an oil shale formation.

[0309]FIG. 130 depicts an embodiment of production of ammonia and ureausing synthesis gas produced from an oil shale formation.

[0310]FIG. 131 depicts an embodiment of preparation of a feed stream foran ammonia and urea process.

[0311]FIG. 132 depicts an embodiment of heat sources in a formation.

[0312]FIG. 133 depicts an embodiment of heat sources in a formation.

[0313]FIG. 134 depicts an embodiment of a heater well with selectiveheating.

[0314]FIG. 135 depicts a cross-sectional representation of an embodimentof production well placed in a formation.

[0315]FIG. 136 depicts an embodiment of a heat source and productionwell pattern.

[0316]FIG. 137 depicts an embodiment of a heat source and productionwell pattern.

[0317]FIG. 138 depicts an embodiment of a heat source and productionwell pattern.

[0318]FIG. 139 depicts an embodiment of a heat source and productionwell pattern.

[0319]FIG. 140 depicts an embodiment of a heat source and productionwell pattern.

[0320]FIG. 141 depicts an embodiment of a heat source and productionwell pattern.

[0321]FIG. 142 depicts an embodiment of a heat source and productionwell pattern.

[0322]FIG. 143 depicts an embodiment of a heat source and productionwell pattern.

[0323]FIG. 144 depicts an embodiment of a heat source and productionwell pattern.

[0324]FIG. 145 depicts an embodiment of a heat source and productionwell pattern.

[0325]FIG. 146 depicts an embodiment of a heat source and productionwell pattern.

[0326]FIG. 147 depicts an embodiment of a heat source and productionwell pattern.

[0327]FIG. 148 depicts an embodiment of a heat source and productionwell pattern.

[0328]FIG. 149 depicts an embodiment of a square pattern of heat sourcesand production wells.

[0329]FIG. 150 depicts an embodiment of a heat source and productionwell pattern.

[0330]FIG. 151 depicts an embodiment of a triangular pattern of heatsources.

[0331]FIG. 152 depicts an embodiment of a square pattern of heatsources.

[0332]FIG. 153 depicts an embodiment of a hexagonal pattern of heatsources.

[0333]FIG. 154 depicts an embodiment of a 12 to 1 pattern of heatsources.

[0334]FIG. 155 depicts an embodiment of surface facilities for treatinga formation fluid.

[0335]FIG. 156 depicts an embodiment of a catalytic flamelessdistributed combustor.

[0336]FIG. 157 depicts an embodiment of surface facilities for treatinga formation fluid.

[0337]FIG. 158 depicts a temperature profile for a triangular pattern ofheat sources.

[0338]FIG. 159 depicts a temperature profile for a square pattern ofheat sources.

[0339]FIG. 160 depicts a temperature profile for a hexagonal pattern ofheat sources.

[0340]FIG. 161 depicts a comparison plot between the average patterntemperature and temperatures at the coldest spots for various patternsof heat sources.

[0341]FIG. 162 depicts a comparison plot between the average patterntemperature and temperatures at various spots within triangular andhexagonal patterns of heat sources.

[0342]FIG. 163 depicts a comparison plot between the average patterntemperature and temperatures at various spots within a square pattern ofheat sources.

[0343]FIG. 164 depicts a comparison plot between temperatures at thecoldest spots of various pattern of heat sources.

[0344]FIG. 165 depicts in situ temperature profiles for electricalresistance heaters and natural distributed combustion heaters.

[0345]FIG. 166 depicts extension of a reaction zone in a heatedformation over time.

[0346]FIG. 167 depicts the ratio of conductive heat transfer toradiative heat transfer in a formation.

[0347]FIG. 168 depicts the ratio of conductive heat transfer toradiative heat transfer in a formation.

[0348]FIG. 169 depicts temperatures of a conductor, a conduit, and anopening in a formation versus a temperature at the face of a formation.

[0349]FIG. 170 depicts temperatures of a conductor, a conduit, and anopening in a formation versus a temperature at the face of a formation.

[0350]FIG. 171 depicts temperatures of a conductor, a conduit, and anopening in a formation versus a temperature at the face of a formation.

[0351]FIG. 172 depicts temperatures of a conductor, a conduit, and anopening in a formation versus a temperature at the face of a formation.

[0352]FIG. 173 depicts a retort and collection system.

[0353]FIG. 174 depicts percentage of hydrocarbon fluid having carbonnumbers greater than 24 as a function of pressure and temperature foroil produced from an oil shale formation.

[0354]FIG. 175 depicts quality of oil as a function of pressure andtemperature for oil produced from an oil shale formation.

[0355]FIG. 176 depicts ethene to ethane ratio produced from an oil shaleformation as a function of temperature and pressure.

[0356]FIG. 177 depicts yield of fluids produced from an oil shaleformation as a function of temperature and pressure.

[0357]FIG. 178 depicts a plot of oil yield produced from treating an oilshale formation.

[0358]FIG. 179 depicts yield of oil produced from treating an oil shaleformation.

[0359]FIG. 180 depicts hydrogen to carbon ratio of hydrocarboncondensate produced from an oil shale formation as a function oftemperature and pressure.

[0360]FIG. 181 depicts olefin to paraffin ratio of hydrocarboncondensate produced from an oil shale formation as a function ofpressure and temperature.

[0361]FIG. 182 depicts relationships between properties of a hydrocarbonfluid produced from an oil shale formation as a function of hydrogenpartial pressure.

[0362]FIG. 183 depicts quantity of oil produced from an oil shaleformation as a function of partial pressure of H₂.

[0363]FIG. 184 depicts ethene to ethane ratios of fluid produced from anoil shale formation as a function of temperature and pressure.

[0364]FIG. 185 depicts hydrogen to carbon atomic ratios of fluidproduced from an oil shale formation as a function of temperature andpressure.

[0365]FIG. 186 depicts a heat source and production well pattern for afield experiment in an oil shale formation.

[0366]FIG. 187 depicts a cross-sectional representation of the fieldexperiment.

[0367]FIG. 188 depicts a plot of temperature within the oil shaleformation during the field experiment.

[0368]FIG. 189 depicts a plot of hydrocarbon liquids production overtime for the in situ field experiment.

[0369]FIG. 190 depicts a plot of production of hydrocarbon liquids, gas,and water for the in situ field experiment.

[0370]FIG. 191 depicts pressure within the oil shale formation duringthe field experiment.

[0371]FIG. 192 depicts a plot of API gravity of a fluid produced fromthe oil shale formation during the field experiment versus time.

[0372]FIG. 193 depicts average carbon numbers of fluid produced from theoil shale formation during the field experiment versus time.

[0373]FIG. 194 depicts density of fluid produced from the oil shaleformation during the field experiment versus time. FIG. 195 depicts aplot of weight percent of hydrocarbons within fluid produced from theoil shale formation during the field experiment.

[0374]FIG. 196 depicts a plot of an average yield of oil from the oilshale formation during the field experiment.

[0375]FIG. 197 depicts oil recovery versus heating rate for experimentaland laboratory oil shale data.

[0376]FIG. 198 depicts total hydrocarbon production and liquid phasefraction versus time of a fluid produced from an oil shale formation.

[0377]FIG. 199 depicts locations of heat sources and wells in anexperimental field test.

[0378]FIG. 200 depicts a cross-sectional representation of the in situexperimental field test.

[0379]FIG. 201 depicts temperature versus time in the experimental fieldtest.

[0380]FIG. 202 depicts temperature versus time in the experimental fieldtest.

[0381]FIG. 203 depicts volatiles produced from a coal formation in theexperimental field test versus cumulative energy content.

[0382]FIG. 204 depicts volume of oil produced from a coal formation inthe experimental field test as a function of energy input.

[0383]FIG. 205 depicts synthesis gas production from the coal formationin the experimental field test versus the total water inflow.

[0384]FIG. 206 depicts additional synthesis gas production from the coalformation in the experimental field test due to injected steam.

[0385]FIG. 207 depicts the effect of methane injection into a heatedformation.

[0386]FIG. 208 depicts the effect of ethane injection into a heatedformation.

[0387]FIG. 209 depicts the effect of propane injection into a heatedformation.

[0388]FIG. 210 depicts the effect of butane injection into a heatedformation.

[0389]FIG. 211 depicts composition of gas produced from a formationversus time.

[0390]FIG. 212 depicts synthesis gas conversion versus time.

[0391]FIG. 213 depicts calculated equilibrium gas dry mole fractions fora reaction of coal with water.

[0392]FIG. 214 depicts calculated equilibrium gas wet mole fractions fora reaction of coal with water.

[0393]FIG. 215 depicts a plot of cumulative adsorbed methane and carbondioxide versus pressure in a coal formation.

[0394]FIG. 216 depicts pressure at a wellhead as a function of time froma numerical simulation.

[0395]FIG. 217 depicts production rate of carbon dioxide and methane asa function of time from a numerical simulation.

[0396]FIG. 218 depicts cumulative methane produced and net carbondioxide injected as a function of time from a numerical simulation.

[0397]FIG. 219 depicts pressure at wellheads as a function of time froma numerical simulation.

[0398]FIG. 220 depicts production rate of carbon dioxide as a functionof time from a numerical simulation.

[0399]FIG. 221 depicts cumulative net carbon dioxide injected as afunction of time from a numerical simulation.

[0400]FIG. 222 depicts a schematic of a surface treatment configurationthat separates formation fluid as it is being produced from a formation.

[0401]FIG. 223 depicts a schematic of a surface facility configurationthat heats a fluid for use in an in situ treatment process and/or asurface facility configuration.

[0402]FIG. 224 depicts a schematic of an embodiment of a fractionatorthat separates component streams from a synthetic condensate.

[0403]FIG. 225 depicts a schematic of an embodiment of a series ofseparating units used to separate component streams from formationfluid.

[0404]FIG. 226 depicts a schematic an embodiment of a series ofseparating units used to separate formation fluid into fractions.

[0405]FIG. 227 depicts a schematic of an embodiment of a surfacetreatment configuration used to reactively distill a syntheticcondensate.

[0406]FIG. 228 depicts a schematic of an embodiment of a surfacetreatment configuration that separates formation fluid throughcondensation.

[0407]FIG. 229 depicts a schematic of an embodiment of a surfacetreatment configuration that hydrotreats untreated formation fluid.

[0408]FIG. 230 depicts a schematic of an embodiment of a surfacetreatment configuration that converts formation fluid into olefins.

[0409]FIG. 231 depicts a schematic of an embodiment of a surfacetreatment configuration that removes a component and converts formationfluid into olefins.

[0410]FIG. 232 depicts a schematic of an embodiment of a surfacetreatment configuration that converts formation fluid into olefins usinga heating unit and a quenching unit.

[0411]FIG. 233 depicts a schematic of an embodiment of a surfacetreatment configuration that separates ammonia and hydrogen sulfide fromwater produced in the formation.

[0412]FIG. 234 depicts a schematic of an embodiment of a surfacetreatment configuration used to produce and separate ammonia.

[0413]FIG. 235 depicts a schematic of an embodiment of a surfacetreatment configuration that separates ammonia and hydrogen sulfide fromwater produced in the formation.

[0414]FIG. 236 depicts a schematic of an embodiment of a surfacetreatment configuration that produces ammonia on site.

[0415]FIG. 237 depicts a schematic of an embodiment of a surfacetreatment configuration used for the synthesis of urea.

[0416]FIG. 238 depicts a schematic of an embodiment of a surfacetreatment configuration that synthesizes ammonium sulfate.

[0417]FIG. 239 depicts an embodiment of surface treatment units used toseparate phenols from formation fluid.

[0418]FIG. 240 depicts a schematic of an embodiment of a surfacetreatment configuration used to separate BTEX compounds from formationfluid.

[0419]FIG. 241 depicts a schematic of an embodiment of a surfacetreatment configuration used to recover BTEX compounds from a naphthafraction.

[0420]FIG. 242 depicts a schematic of an embodiment of a surfacetreatment configuration that separates a component from a heart cut.

[0421]FIG. 243 illustrates experiments performed in a batch mode.

[0422]FIG. 244 depicts a plan view representation of an embodiment oftreatment areas formed by perimeter barriers.

[0423]FIG. 245 depicts a side representation of an embodiment of an insitu conversion process system used to treat a thin rich formation.

[0424]FIG. 246 depicts a side representation of an embodiment of an insitu conversion process system used to treat a thin rich formation.

[0425]FIG. 247 depicts a side representation of an embodiment of an insitu conversion process system.

[0426]FIG. 248 depicts a side representation of an embodiment of an insitu conversion process system with an installed upper perimeter barrierand an installed lower perimeter barrier.

[0427]FIG. 249 depicts a plan view representation of an embodiment oftreatment areas formed by perimeter barriers having arced portions,wherein the centers of the arced portions are in an equilateral trianglepattern.

[0428]FIG. 250 depicts a plan view representation of an embodiment oftreatment areas formed by perimeter barriers having arced portions,wherein the centers of the arced portions are in a square pattern.

[0429]FIG. 251 depicts a plan view representation of an embodiment oftreatment areas formed by perimeter barriers radially positioned arounda central point.

[0430]FIG. 252 depicts a plan view representation of a portion of atreatment area defined by a double ring of freeze wells.

[0431]FIG. 253 depicts a side representation of a freeze well that isdirectionally drilled in a formation so that the freeze well enters theformation in a first location and exits the formation in a secondlocation.

[0432]FIG. 254 depicts a side representation of freeze wells that form abarrier along sides and ends of a dipping hydrocarbon containing layerin a formation.

[0433]FIG. 255 depicts a representation of an embodiment of a freezewell and an embodiment of a heat source that may be used during an insitu conversion process.

[0434]FIG. 256 depicts an embodiment of a batch operated freeze well.

[0435]FIG. 257 depicts an embodiment of a batch operated freeze wellhaving an open wellbore portion.

[0436]FIG. 258 depicts a plan view representation of a circulated fluidrefrigeration system.

[0437]FIG. 259 shows simulation results as a plot of time to reduce atemperature midway between two freeze wells versus well spacing.

[0438]FIG. 260 depicts an embodiment of a freeze well for a circulatedliquid refrigeration system, wherein a cutaway view of the freeze wellis represented below ground surface.

[0439]FIG. 261 depicts an embodiment of a freeze well for a circulatedliquid refrigeration system.

[0440]FIG. 262 depicts an embodiment of a freeze well for a circulatedliquid refrigeration system.

[0441]FIG. 263 depicts results of a simulation for Green River oil shalepresented as temperature versus time for a formation cooled with arefrigerant.

[0442]FIG. 264 depicts a plan view representation of low temperaturezones formed by freeze wells placed in a formation through which fluidflows slowly enough to allow for formation of an interconnected lowtemperature zone.

[0443]FIG. 265 depicts a plan view representation of low temperaturezones formed by freeze wells placed in a formation through which fluidflows at too high a flow rate to allow for formation of aninterconnected low temperature zone.

[0444]FIG. 266 depicts thermal simulation results of a heat sourcesurrounded by a ring of freeze wells.

[0445]FIG. 267 depicts a representation of an embodiment of a groundcover.

[0446]FIG. 268 depicts an embodiment of a treatment area surrounded by aring of dewatering wells.

[0447]FIG. 269 depicts an embodiment of a treatment area surrounded bytwo rings of dewatering wells.

[0448]FIG. 270 depicts an embodiment of a treatment area surrounded bythree rings of dewatering wells.

[0449]FIG. 271 illustrates a schematic of an embodiment of an injectionwellbore and a production wellbore.

[0450]FIG. 272 depicts an embodiment of a remediation process used totreat a treatment area.

[0451]FIG. 273 depicts an embodiment of a heated formation used as aradial distillation column.

[0452]FIG. 274 depicts an embodiment of a heated formation used forseparation of hydrocarbons and contaminants.

[0453]FIG. 275 depicts an embodiment for recovering heat from a heatedformation and transferring the heat to an above-ground processing unit.

[0454]FIG. 276 depicts an embodiment for recovering heat from oneformation and providing heat to another formation with an intermediateproduction step.

[0455]FIG. 277 depicts an embodiment for recovering heat from oneformation and providing heat to another formation in situ.

[0456]FIG. 278 depicts an embodiment of a region of reaction within aheated formation.

[0457]FIG. 279 depicts an embodiment of a conduit placed within a heatedformation.

[0458]FIG. 280 depicts an embodiment of a U-shaped conduit placed withina heated formation.

[0459]FIG. 281 depicts an embodiment for sequestration of carbon dioxidein a heated formation.

[0460]FIG. 282 depicts an embodiment for solution mining a formation.

[0461]FIG. 283 illustrates cumulative oil production and cumulative heatinput versus time using an in situ conversion process for solution minedoil shale and for pre-solution mined oil shale.

[0462]FIG. 284 is a flow chart illustrating options for produced fluidsfrom a shut-in formation.

[0463]FIG. 285 illustrates a schematic of an embodiment of an injectionwellbore and a production wellbore.

[0464]FIG. 286 illustrates a cross-sectional representation of in situtreatment of a formation with steam injection according to oneembodiment.

[0465]FIG. 287 illustrates a cross-sectional representation of in situtreatment of a formation with steam injection according to oneembodiment.

[0466]FIG. 288 illustrates a cross-sectional representation of in situtreatment of a formation with steam injection according to oneembodiment.

[0467] While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and may herein be described in detail. Thedrawings may not be to scale. It should be understood, however, that thedrawings and detailed description thereto are not intended to limit theinvention to the particular form disclosed, but on the contrary, theintention is to cover all modifications, equivalents and alternativesfalling within the spirit and scope of the present invention as definedby the appended claims.

DETAILED DESCRIPTION OF THE INVENTION

[0468] The following description generally relates to systems andmethods for treating an oil shale formation. Such formations may betreated to yield relatively high quality hydrocarbon products, hydrogen,and other products.

[0469] Alto “Hydrocarbons” are organic material with molecularstructures containing carbon and hydrogen. Hydrocarbons may also includeother elements, such as, but not limited to, halogens, metallicelements, nitrogen, oxygen, and/or sulfur. Hydrocarbons may be, but arenot limited to, kerogen, bitumen, pyrobitumen, oils, natural mineralwaxes, and asphaltites. Hydrocarbons may be located within or adjacentto mineral matrices within the earth. Matrices may include, but are notlimited to, sedimentary rock, sands, silicilytes, carbonates,diatomites, and other porous media. “Hydrocarbon fluids” are fluids thatinclude hydrocarbons. Hydrocarbon fluids may include, entrain, or beentrained in non-hydrocarbon fluids (e.g., hydrogen (“H₂”), nitrogen(“N₂”), carbon monoxide, carbon dioxide, hydrogen sulfide, water, andammonia).

[0470] A “formation” includes one or more hydrocarbon containing layers,one or more non-hydrocarbon layers, an overburden, and/or anunderburden. An “overburden” and/or an “underburden” includes one ormore different types of impermeable materials. For example, overburdenand/or underburden may include rock, shale, mudstone, or wet/tightcarbonate (i.e., an impermeable carbonate without hydrocarbons). In someembodiments of in situ conversion processes, an overburden and/or anunderburden may include a hydrocarbon containing layer or hydrocarboncontaining layers that are relatively impermeable and are not subjectedto temperatures during in situ conversion processing that results insignificant characteristic changes of the hydrocarbon containing layersof the overburden and/or underburden. For example, an underburden maycontain shale or mudstone. In some cases, the overburden and/orunderburden may be somewhat permeable.

[0471] “Kerogen” is a solid, insoluble hydrocarbon that has beenconverted by natural degradation (e.g., by diagenesis) and thatprincipally contains carbon, hydrogen, nitrogen, oxygen, and sulfur. Oilshale contains kerogens. “Bitumen” is a non-crystalline solid or viscoushydrocarbon material that is substantially soluble in carbon disulfide.“Oil” is a fluid containing a mixture of condensable hydrocarbons.

[0472] The terms “formation fluids” and “produced fluids” refer tofluids removed from an oil shale formation and may include pyrolyzationfluid, synthesis gas, mobilized hydrocarbon, and water (steam). The term“mobilized fluid” refers to fluids within the formation that are able toflow because of thermal treatment of the formation. Formation fluids mayinclude hydrocarbon fluids as well as non-hydrocarbon fluids.

[0473] “Carbon number” refers to a number of carbon atoms within amolecule. A hydrocarbon fluid may include various hydrocarbons havingvarying numbers of carbon atoms. The hydrocarbon fluid may be describedby a carbon number distribution. Carbon numbers and/or carbon numberdistributions may be determined by true boiling point distributionand/or gas-liquid chromatography.

[0474] A “heat source” is any system for providing heat to at least aportion of a formation substantially by conductive and/or radiative heattransfer. For example, a heat source may include electric heaters suchas an insulated conductor, an elongated member, and a conductor disposedwithin a conduit, as described in embodiments herein. A heat source mayalso include heat sources that generate heat by burning a fuel externalto or within a formation, such as surface burners, downhole gas burners,flameless distributed combustors, and natural distributed combustors, asdescribed in embodiments herein. In addition, it is envisioned that insome embodiments heat provided to or generated in one or more heatsources may by supplied by other sources of energy. The other sources ofenergy may directly heat a formation, or the energy may be applied to atransfer media that directly or indirectly heats the formation. It is tobe understood that one or more heat sources that are applying heat to aformation may use different sources of energy. Thus, for example, for agiven formation some heat sources may supply heat from electricresistance heaters, some heat sources may provide heat from combustion,and some heat sources may provide heat from one or more other energysources (e.g., chemical reactions, solar energy, wind energy, biomass,or other sources of renewable energy). A chemical reaction may includean exothermic reaction (e.g., an oxidation reaction). A heat source mayalso include a heater that may provide heat to a zone proximate and/orsurrounding a heating location such as a heater well.

[0475] A “heater” is any system for generating heat in a well or a nearwellbore region. Heaters may be, but are not limited to, electricheaters, burners, combustors (e.g., natural distributed combustors) thatreact with material in or produced from a formation, and/or combinationsthereof. A “unit of heat sources” refers to a number of heat sourcesthat form a template that is repeated to create a pattern of heatsources within a formation.

[0476] The term “wellbore” refers to a hole in a formation made bydrilling or insertion of a conduit into the formation. A wellbore mayhave a substantially circular cross section, or other cross-sectionalshapes (e.g., circles, ovals, squares, rectangles, triangles, slits, orother regular or irregular shapes). As used herein, the terms “well” and“opening,” when referring to an opening in the formation may be usedinterchangeably with the term “wellbore.”

[0477] “Natural distributed combustor” refers to a heater that uses anoxidant to oxidize at least a portion of the carbon in the formation togenerate heat, and wherein the oxidation takes place in a vicinityproximate a wellbore. Most of the combustion products produced in thenatural distributed combustor are removed through the wellbore.

[0478] “Orifices,” refers to openings (e.g., openings in conduits)having a wide variety of sizes and cross-sectional shapes including, butnot limited to, circles, ovals, squares, rectangles, triangles, slits,or other regular or irregular shapes.

[0479] “Reaction zone” refers to a volume of an oil shale formation thatis subjected to a chemical reaction such as an oxidation reaction.

[0480] “Insulated conductor” refers to any elongated material that isable to conduct electricity and that is covered, in whole or in part, byan electrically insulating material. The term “self-controls” refers tocontrolling an output of a heater without external control of any type.

[0481] “Pyrolysis” is the breaking of chemical bonds due to theapplication of heat. For example, pyrolysis may include transforming acompound into one or more other substances by heat alone. Heat may betransferred to a section of the formation to cause pyrolysis.

[0482] “Pyrolyzation fluids” or “pyrolysis products” refers to fluidproduced substantially during pyrolysis of hydrocarbons. Fluid producedby pyrolysis reactions may mix with other fluids in a formation. Themixture would be considered pyrolyzation fluid or pyrolyzation product.As used herein, “pyrolysis zone” refers to a volume of a formation thatis reacted or reacting to form a pyrolyzation fluid.

[0483] “Cracking” refers to a process involving decomposition andmolecular recombination of organic compounds to produce a greater numberof molecules than were initially present. In cracking, a series ofreactions take place accompanied by a transfer of hydrogen atoms betweenmolecules. For example, naphtha may undergo a thermal cracking reactionto form ethene and H₂.

[0484] “Superposition of heat” refers to providing heat from two or moreheat sources to a selected section of a formation such that thetemperature of the formation at least at one location between the heatsources is influenced by the heat sources.

[0485] “Fingering” refers to injected fluids bypassing portions of aformation because of variations in transport characteristics of theformation (e.g., permeability or porosity).

[0486] “Thermal conductivity” is a property of a material that describesthe rate at which heat flows, in steady state, between two surfaces ofthe material for a given temperature difference between the twosurfaces.

[0487] “Fluid pressure” is a pressure generated by a fluid within aformation. “Lithostatic pressure” (sometimes referred to as “lithostaticstress”) is a pressure within a formation equal to a weight per unitarea of an overlying rock mass. “Hydrostatic pressure” is a pressurewithin a formation exerted by a column of water.

[0488] “Condensable hydrocarbons” are hydrocarbons that condense at 25°C. at one atmosphere absolute pressure. Condensable hydrocarbons mayinclude a mixture of hydrocarbons having carbon numbers greater than 4.“Non-condensable hydrocarbons” are hydrocarbons that do not condense at25° C. and one atmosphere absolute pressure. Non-condensablehydrocarbons may include hydrocarbons having carbon numbers less than 5.

[0489] “Olefins” are molecules that include unsaturated hydrocarbonshaving one or more non-aromatic carbon-to-carbon double bonds.

[0490] “Urea” describes a compound represented by the molecular formulaof NH₂—CO—NH₂. Urea may be used as a fertilizer.

[0491] “Synthesis gas” is a mixture including hydrogen and carbonmonoxide used for synthesizing a wide range of compounds. Additionalcomponents of synthesis gas may include water, carbon dioxide, nitrogen,methane, and other gases. Synthesis gas may be generated by a variety ofprocesses and feedstocks.

[0492] “Reforming” is a reaction of hydrocarbons (such as methane ornaphtha) with steam to produce CO and H₂ as major products. Generally,it is conducted in the presence of a catalyst, although it can beperformed thermally without the presence of a catalyst.

[0493] “Sequestration” refers to storing a gas that is a by-product of aprocess rather than venting the gas to the atmosphere.

[0494] “Dipping” refers to a formation that slopes downward or inclinesfrom a plane parallel to the earth's surface, assuming the plane is flat(i.e., a “horizontal” plane). A “dip” is an angle that a stratum orsimilar feature makes with a horizontal plane. A “steeply dipping” oilshale formation refers to an oil shale formation lying at an angle of atleast 20° from a horizontal plane. “Down dip” refers to downward along adirection parallel to a dip in a formation. “Up dip” refers to upwardalong a direction parallel to a dip of a formation. “Strike” refers tothe course or bearing of hydrocarbon material that is normal to thedirection of dip.

[0495] “Subsidence” is a downward movement of a portion of a formationrelative to an initial elevation of the surface.

[0496] “Thickness” of a layer refers to the thickness of a cross sectionof a layer, wherein the cross section is normal to a face of the layer.

[0497] “Coring” is a process that generally includes drilling a holeinto a formation and removing a substantially solid mass of theformation from the hole.

[0498] A “surface unit” is an ex situ treatment unit.

[0499] “Middle distillates” refers to hydrocarbon mixtures with aboiling point range that corresponds substantially with that of keroseneand gas oil fractions obtained in a conventional atmosphericdistillation of crude oil material. The middle distillate boiling pointrange may include temperatures between about 150° C. and about 360° C.,with a fraction boiling point between about 200° C. and about 360° C.Middle distillates may be referred to as gas oil.

[0500] A “boiling point cut” is a hydrocarbon liquid fraction that maybe separated from hydrocarbon liquids when the hydrocarbon liquids areheated to a boiling point range of the fraction.

[0501] “Selected mobilized section” refers to a section of a formationthat is at an average temperature within a mobilization temperaturerange. “Selected pyrolyzation section” refers to a section of aformation that is at an average temperature within a pyrolyzationtemperature range.

[0502] “Enriched air” refers to air having a larger mole fraction ofoxygen than air in the atmosphere. Enrichment of air is typically doneto increase its combustion-supporting ability.

[0503] “Heavy hydrocarbons” are viscous hydrocarbon fluids. Heavyhydrocarbons may include highly viscous hydrocarbon fluids such as heavyoil, tar, and/or asphalt. Heavy hydrocarbons may include carbon andhydrogen, as well as smaller concentrations of sulfur, oxygen, andnitrogen. Additional elements may also be present in heavy hydrocarbonsin trace amounts. Heavy hydrocarbons may be classified by API gravity.Heavy hydrocarbons generally have an API gravity below about 20°. Heavyoil, for example, generally has an API gravity of about 10-20°, whereastar generally has an API gravity below about 10°. The viscosity of heavyhydrocarbons is generally greater than about 100 centipoise at 15° C.Heavy hydrocarbons may also include aromatics or other complex ringhydrocarbons.

[0504] “Tar” is a viscous hydrocarbon that generally has a viscositygreater than about 10,000 centipoise at 15° C. The specific gravity oftar generally is greater than 1.000. Tar may have an API gravity lessthan 10°.

[0505] “Upgrade” refers to increasing the quality of hydrocarbons. Forexample, upgrading heavy hydrocarbons may result in an increase in theAPI gravity of the heavy hydrocarbons.

[0506] “Off peak” times refers to times of operation when utility energyis less commonly used and, therefore, less expensive.

[0507] “Thermal fracture” refers to fractures created in a formationcaused by expansion or contraction of a formation and/or fluids withinthe formation, which is in turn caused by increasing/decreasing thetemperature of the formation and/or fluids within the formation, and/orby increasing/decreasing a pressure of fluids within the formation dueto heating.

[0508] “Vertical hydraulic fracture” refers to a fracture at leastpartially propagated along a vertical plane in a formation, wherein thefracture is created through injection of fluids into a formation.

[0509] Hydrocarbons in formations may be treated in various ways toproduce many different products. In certain embodiments, such formationsmay be treated in stages. FIG. 1 illustrates several stages of heatingan oil shale formation. FIG. 1 also depicts an example of yield (barrelsof oil equivalent per ton) (y axis) of formation fluids from an oilshale formation versus temperature (° C.) (x axis) of the formation.

[0510] Desorption of methane and vaporization of water occurs duringstage 1 heating. Heating of the formation through stage 1 may beperformed as quickly as possible. For example, when an oil shaleformation is initially heated, hydrocarbons in the formation may desorbadsorbed methane. The desorbed methane may be produced from theformation. If the oil shale formation is heated further, water withinthe oil shale formation may be vaporized. Water may occupy, in some oilshale formations, between about 10% to about 50% of the pore volume inthe formation. In other formations, water may occupy larger or smallerportions of the pore volume. Water typically is vaporized in a formationbetween about 160° C. and about 285° C. for pressures of about 6 barsabsolute to 70 bars absolute. In some embodiments, the vaporized watermay produce wettability changes in the formation and/or increaseformation pressure. The wettability changes and/or increased pressuremay affect pyrolysis reactions or other reactions in the formation. Incertain embodiments, the vaporized water may be produced from theformation. In other embodiments, the vaporized water may be used forsteam extraction and/or distillation in the formation or outside theformation. Removing the water from and increasing the pore volume in theformation may increase the storage space for hydrocarbons within thepore volume.

[0511] After stage 1 heating, the formation may be heated further, suchthat a temperature within the formation reaches (at least) an initialpyrolyzation temperature (e.g., a temperature at the lower end of thetemperature range shown as stage 2). Hydrocarbons within the formationmay be pyrolyzed throughout stage 2. A pyrolysis temperature range mayvary depending on types of hydrocarbons within the formation. Apyrolysis temperature range may include temperatures between about 250°C. and about 900° C. A pyrolysis temperature range for producing desiredproducts may extend through only a portion of the total pyrolysistemperature range. In some embodiments, a pyrolysis temperature rangefor producing desired products may include temperatures between about250° C. to about 400° C. If a temperature of hydrocarbons in a formationis slowly raised through a temperature range from about 250° C. to about400° C., production of pyrolysis products may be substantially completewhen the temperature approaches 400° C. Heating the oil shale formationwith a plurality of heat sources may establish thermal gradients aroundthe heat sources that slowly raise the temperature of hydrocarbons inthe formation through a pyrolysis temperature range.

[0512] In some in situ conversion embodiments, a temperature of thehydrocarbons to be subjected to pyrolysis may not be slowly increasedthroughout a temperature range from about 250° C. to about 400° C. Thehydrocarbons in the formation may be heated to a desired temperature(e.g., about 325° C.). Other temperatures may be selected as the desiredtemperature. Superposition of heat from heat sources may allow thedesired temperature to be relatively quickly and efficiently establishedin the formation. Energy input into the formation from the heat sourcesmay be adjusted to maintain the temperature in the formationsubstantially at the desired temperature. The hydrocarbons may bemaintained substantially at the desired temperature until pyrolysisdeclines such that production of desired formation fluids from theformation becomes uneconomical.

[0513] Formation fluids including pyrolyzation fluids may be producedfrom the formation. The pyrolyzation fluids may include, but are notlimited to, hydrocarbons, hydrogen, carbon dioxide, carbon monoxide,hydrogen sulfide, ammonia, nitrogen, water, and mixtures thereof. As thetemperature of the formation increases, the amount of condensablehydrocarbons in the produced formation fluid tends to decrease. At hightemperatures, the formation may produce mostly methane and/or hydrogen.If an oil shale formation is heated throughout an entire pyrolysisrange, the formation may produce only small amounts of hydrogen towardsan upper limit of the pyrolysis range. After all of the availablehydrogen is depleted, a minimal amount of fluid production from theformation will typically occur.

[0514] After pyrolysis of hydrocarbons, a large amount of carbon andsome hydrogen may still be present in the formation. A significantportion of remaining carbon in the formation can be produced from theformation in the form of synthesis gas. Synthesis gas generation maytake place during stage 3 heating depicted in FIG. 1. Stage 3 mayinclude heating an oil shale formation to a temperature sufficient toallow synthesis gas generation. For example, synthesis gas may beproduced within a temperature range from about 400° C. to about 1200° C.The temperature of the formation when the synthesis gas generating fluidis introduced to the formation may determine the composition ofsynthesis gas produced within the formation. If a synthesis gasgenerating fluid is introduced into a formation at a temperaturesufficient to allow synthesis gas generation, synthesis gas may begenerated within the formation. The generated synthesis gas may beremoved from the formation through a production well or productionwells. A large volume of synthesis gas may be produced during generationof synthesis gas.

[0515] Total energy content of fluids produced from an oil shaleformation may stay relatively constant throughout pyrolysis andsynthesis gas generation. During pyrolysis at relatively low formationtemperatures, a significant portion of the produced fluid may becondensable hydrocarbons that have a high energy content. At higherpyrolysis temperatures, however, less of the formation fluid may includecondensable hydrocarbons. More non-condensable formation fluids may beproduced from the formation. Energy content per unit volume of theproduced fluid may decline slightly during generation of predominantlynon-condensable formation fluids. During synthesis gas generation,energy content per unit volume of produced synthesis gas declinessignificantly compared to energy content of pyrolyzation fluid. Thevolume of the produced synthesis gas, however, will in many instancesincrease substantially, thereby compensating for the decreased energycontent.

[0516]FIG. 2 depicts a van Krevelen diagram. The van Krevelen diagram isa plot of atomic hydrogen to carbon ratio (y axis) versus atomic oxygento carbon ratio (x axis) for various types of kerogen. The van Krevelendiagram shows the maturation sequence for various types of kerogen thattypically occurs over geologic time due to temperature, pressure, andbiochemical degradation. The maturation sequence may be accelerated byheating in situ at a controlled rate and/or a controlled pressure.

[0517] A van Krevelen diagram may be useful for selecting a resource forpracticing various embodiments. Treating a formation containing kerogenin region 5 may produce carbon dioxide, non-condensable hydrocarbons,hydrogen, and water, along with a relatively small amount of condensablehydrocarbons. Treating a formation containing kerogen in region 7 mayproduce condensable and non-condensable hydrocarbons, carbon dioxide,hydrogen, and water. Treating a formation containing kerogen in region 9will in many instances produce methane and hydrogen. A formationcontaining kerogen in region 7 may be selected for treatment becausetreating region 7 kerogen may produce large quantities of valuablehydrocarbons, and low quantities of undesirable products such as carbondioxide and water. A region 7 kerogen may produce large quantities ofvaluable hydrocarbons and low quantities of undesirable products becausethe region 7 kerogen has already undergone dehydration and/ordecarboxylation over geological time. In addition, region 7 kerogen canbe further treated to make other useful products (e.g., methane,hydrogen, and/or synthesis gas) as the kerogen transforms to region 9kerogen.

[0518] If a formation containing kerogen in region 5 or region 7 isselected for in situ conversion, in situ thermal treatment mayaccelerate maturation of the kerogen along paths represented by arrowsin FIG. 2. For example, region 5 kerogen may transform to region 7kerogen and possibly then to region 9 kerogen. Region 7 kerogen maytransform to region 9 kerogen. In situ conversion may expeditematuration of kerogen and allow production of valuable products from thekerogen.

[0519] If region 5 kerogen is treated, a substantial amount of carbondioxide may be produced due to decarboxylation of hydrocarbons in theformation. In addition to carbon dioxide, region 5 kerogen may producesome hydrocarbons (e.g., methane). Treating region 5 kerogen may producesubstantial amounts of water due to dehydration of kerogen in theformation. Production of water from kerogen may leave hydrocarbonsremaining in the formation enriched in carbon. Oxygen content of thehydrocarbons may decrease faster than hydrogen content of thehydrocarbons during production of such water and carbon dioxide from theformation. Therefore, production of such water and carbon dioxide fromregion 5 kerogen may result in a larger decrease in the atomic oxygen tocarbon ratio than a decrease in the atomic hydrogen to carbon ratio (seeregion 5 arrows in FIG. 2 which depict more horizontal than verticalmovement).

[0520] If region 7 kerogen is treated, some of the hydrocarbons in theformation may be pyrolyzed to produce condensable and non-condensablehydrocarbons. For example, treating region 7 kerogen may result inproduction of oil from hydrocarbons, as well as some carbon dioxide andwater. In situ conversion of region 7 kerogen may produce significantlyless carbon dioxide and water than is produced during in situ conversionof region 5 kerogen. Therefore, the atomic hydrogen to carbon ratio ofthe kerogen may decrease rapidly as the kerogen in region 7 is treated.The atomic oxygen to carbon ratio of the region 7 kerogen may decreasemuch slower than the atomic hydrogen to carbon ratio of the region 7kerogen.

[0521] Kerogen in region 9 may be treated to generate methane andhydrogen. For example, if such kerogen was previously treated (e.g., itwas previously region 7 kerogen), then after pyrolysis longerhydrocarbon chains of the hydrocarbons may have cracked and beenproduced from the formation. Carbon and hydrogen, however, may still bepresent in the formation.

[0522] If kerogen in region 9 were heated to a synthesis gas generatingtemperature and a synthesis gas generating fluid (e.g., steam) wereadded to the region 9 kerogen, then at least a portion of remaininghydrocarbons in the formation may be produced from the formation in theform of synthesis gas. For region 9 kerogen, the atomic hydrogen tocarbon ratio and the atomic oxygen to carbon ratio in the hydrocarbonsmay significantly decrease as the temperature rises. Hydrocarbons in theformation may be transformed into relatively pure carbon in region 9.Heating region 9 kerogen to still higher temperatures will tend totransform such kerogen into graphite 11.

[0523] An oil shale formation may have a number of properties thatdepend on a composition of the hydrocarbons within the formation. Suchproperties may affect the composition and amount of products that areproduced from an oil shale formation during in situ conversion.Properties of an oil shale formation may be used to determine if and/orhow an oil shale formation is to be subjected to in situ conversion.

[0524] Kerogen is composed of organic matter that has been transformeddue to a maturation process. The maturation process for kerogen mayinclude two stages: a biochemical stage and a geochemical stage. Thebiochemical stage typically involves degradation of organic material byaerobic and/or anaerobic organisms. The geochemical stage typicallyinvolves conversion of organic matter due to temperature changes andsignificant pressures. During maturation, oil and gas may be produced asthe organic matter of the kerogen is transformed.

[0525] The van Krevelen diagram shown in FIG. 2 classifies variousnatural deposits of kerogen. For example, kerogen may be classified intofour distinct groups: type I, type II, type III, and type IV, which areillustrated by the four branches of the van Krevelen diagram. The vanKrevelen diagram shows the maturation sequence for kerogen thattypically occurs over geological time due to temperature and pressure.Classification of kerogen type may depend upon precursor materials ofthe kerogen. The precursor materials transform over time into macerals.Macerals are microscopic structures that have different structures andproperties depending on the precursor materials from which they arederived. Oil shale may be described as a kerogen type I or type II, andmay primarily contain macerals from the liptinite group. Liptinites arederived from plants, specifically the lipid rich and resinous parts. Theconcentration of hydrogen within liptinite may be as high as 9 weight %.In addition, liptinite has a relatively high hydrogen to carbon ratioand a relatively low atomic oxygen to carbon ratio.

[0526] A type I kerogen may be classified as an alginite, since type Ikerogen developed primarily from algal bodies. Type I kerogen may resultfrom deposits made in lacustrine environments. Type II kerogen maydevelop from organic matter that was deposited in marine environments.

[0527] Type III kerogen may generally include vitrinite macerals.Vitrinite is derived from cell walls and/or woody tissues (e.g., stems,branches, leaves, and roots of plants). Type III kerogen may be presentin most humic coals. Type III kerogen may develop from organic matterthat was deposited in swamps. Type IV kerogen includes the inertinitemaceral group. The inertinite maceral group is composed of plantmaterial such as leaves, bark, and stems that have undergone oxidationduring the early peat stages of burial diagenesis. Inertinite maceral ischemically similar to vitrinite, but has a high carbon and low hydrogencontent.

[0528] The dashed lines in FIG. 2 correspond to vitrinite reflectance.Vitrinite reflectance is a measure of maturation. As kerogen undergoesmaturation, the composition of the kerogen usually changes due toexpulsion of volatile matter (e.g., carbon dioxide, methane, and oil)from the kerogen. Rank classifications of kerogen indicate the level towhich kerogen has matured. For example, as kerogen undergoes maturation,the rank of kerogen increases. As rank increases, the volatile matterwithin, and producible from, the kerogen tends to decrease. In addition,the moisture content of kerogen generally decreases as the rankincreases. At higher ranks, the moisture content may reach a relativelyconstant value. Higher rank kerogens that have undergone significantmaturation tend to have a higher carbon content and a lower volatilematter content than lower rank kerogens such as lignite.

[0529] Oil shale formations may be selected for in situ conversion basedon properties of at least a portion of the formation. For example, aformation may be selected based on richness, thickness, and/or depth(i.e., thickness of overburden) of the formation. In addition, the typesof fluids producible from the formation may be a factor in the selectionof a formation for in situ conversion. In certain embodiments, thequality of the fluids to be produced may be assessed in advance oftreatment. Assessment of the products that may be produced from aformation may generate significant cost savings since only formationsthat will produce desired products need to be subjected to in situconversion. Properties that may be used to assess hydrocarbons in aformation include, but are not limited to, an amount of hydrocarbonliquids that may be produced from the hydrocarbons, a likely API gravityof the produced hydrocarbon liquids, an amount of hydrocarbon gasproducible from the formation, and/or an amount of carbon dioxide andwater that in situ conversion will generate.

[0530] Another property that may be used to assess the quality of fluidsproduced from certain kerogen containing formations is vitrinitereflectance. Such formations include, but are not limited to, oil shaleformations. Oil shale formations that include kerogen may beassessed/selected for treatment based on a vitrinite reflectance of thekerogen. Vitrinite reflectance is often related to a hydrogen to carbonatomic ratio of a kerogen and an oxygen to carbon atomic ratio of thekerogen, as shown by the dashed lines in FIG. 2. A van Krevelen diagrammay be useful in selecting a resource for an in situ conversion process.

[0531] Vitrinite reflectance of a kerogen in an oil shale formation mayindicate which fluids are producible from a formation upon heating. Forexample, a vitrinite reflectance of approximately 0.5% to approximately1.5% may indicate that the kerogen will produce a large quantity ofcondensable fluids. In addition, a vitrinite reflectance ofapproximately 1.5% to 3.0% may indicate a kerogen in region 9 asdescribed above. If an oil shale formation having such kerogen isheated, a significant amount (e.g., a majority) of the fluid produced bysuch heating may include methane and hydrogen. The formation may be usedto generate synthesis gas if the temperature is raised sufficiently highand a synthesis gas generating fluid is introduced into the formation.

[0532] A kerogen containing formation to be subjected to in situconversion may be chosen based on a vitrinite reflectance. The vitrinitereflectance of the kerogen may indicate that the formation will producehigh quality fluids when subjected to in situ conversion. In some insitu conversion embodiments, a portion of the kerogen containingformation to be subjected to in situ conversion may have a vitrinitereflectance in a range between about 0.2% and about 3.0%. In some insitu conversion embodiments, a portion of the kerogen containingformation may have a vitrinite reflectance from about 0.5% to about2.0%. In some in situ conversion embodiments, a portion of the kerogencontaining formation may have a vitrinite reflectance from about 0.5% toabout 1.0%.

[0533] In some in situ conversion embodiments, an oil shale formationmay be selected for treatment based on a hydrogen content within thehydrocarbons in the formation. For example, a method of treating an oilshale formation may include selecting a portion of the oil shaleformation for treatment having hydrocarbons with a hydrogen contentgreater than about 3 weight %, 3.5 weight %, or 4 weight % when measuredon a dry, ash-free basis. In addition, a selected section of an oilshale formation may include hydrocarbons with an atomic hydrogen tocarbon ratio that falls within a range from about 0.5 to about 2, and inmany instances from about 0.70 to about 1.65.

[0534] Hydrogen content of an oil shale formation may significantlyinfluence a composition of hydrocarbon fluids producible from theformation. Pyrolysis of hydrocarbons within heated portions of theformation may generate hydrocarbon fluids that include a double bond ora radical. Hydrogen within the formation may reduce the double bond to asingle bond. Reaction of generated hydrocarbon fluids with each otherand/or with additional components in the formation may be inhibited. Forexample, reduction of a double bond of the generated hydrocarbon fluidsto a single bond may reduce polymerization of the generatedhydrocarbons. Such polymerization may reduce the amount of fluidsproduced and may reduce the quality of fluid produced from theformation.

[0535] Hydrogen within the formation may neutralize radicals in thegenerated hydrocarbon fluids. Hydrogen present in the formation mayinhibit reaction of hydrocarbon fragments by transforming thehydrocarbon fragments into relatively short chain hydrocarbon fluids.The hydrocarbon fluids may enter a vapor phase. Vapor phase hydrocarbonsmay move relatively easily through the formation to production wells.Increase in the hydrocarbon fluids in the vapor phase may significantlyreduce a potential for producing less desirable products within theselected section of the formation.

[0536] A lack of bound and free hydrogen in the formation may negativelyaffect the amount and quality of fluids that can be produced from theformation. If too little hydrogen is naturally present, then hydrogen orother reducing fluids may be added to the formation.

[0537] When heating a portion of an oil shale formation, oxygen withinthe portion may form carbon dioxide. A formation may be chosen and/orconditions in a formation may be adjusted to inhibit production ofcarbon dioxide and other oxides. In an embodiment, production of carbondioxide may be reduced by selecting and treating a portion of an oilshale formation having a vitrinite reflectance of greater than about0.5%.

[0538] An amount of carbon dioxide that can be produced from a kerogencontaining formation may be dependent on an oxygen content initiallypresent in the formation and/or an atomic oxygen to carbon ratio of thekerogen. In some in situ conversion embodiments, formations to besubjected to in situ conversion may include kerogen with an atomicoxygen weight percentage of less than about 20 weight %, 15 weight %,and/or 10 weight %. In some in situ conversion embodiments, formationsto be subjected to in situ conversion may include kerogen with an atomicoxygen to carbon ratio of less than about 0.15. In some in situconversion embodiments, a formation selected for treatment may have anatomic oxygen to carbon ratio of about 0.03 to about 0.12.

[0539] Heating an oil shale formation may include providing a largeamount of energy to heat sources located within the formation. Oil shaleformations may also contain some water. A significant portion of energyinitially provided to a formation may be used to heat water within theformation. An initial rate of temperature increase may be reduced by thepresence of water in the formation. Excessive amounts of heat and/ortime may be required to heat a formation having a high moisture contentto a temperature sufficient to pyrolyze hydrocarbons in the formation.In certain embodiments, water may be inhibited from flowing into aformation subjected to in situ conversion. A formation to be subjectedto in situ conversion may have a low initial moisture content. Theformation may have an initial moisture content that is less than about15 weight %. Some formations that are to be subjected to in situconversion may have an initial moisture content of less than about 10weight %. Other formations that are to be processed using an in situconversion process may have initial moisture contents that are greaterthan about 15 weight %. Formations with initial moisture contents aboveabout 15 weight % may incur significant energy costs to remove the waterthat is initially present in the formation during heating to pyrolysistemperatures.

[0540] An oil shale formation may be selected for treatment based onadditional factors such as, but not limited to, thickness of hydrocarboncontaining layers within the formation, assessed liquid productioncontent, location of the formation, and depth of hydrocarbon containinglayers. An oil shale formation may include multiple layers. Such layersmay include hydrocarbon containing layers, as well as layers that arehydrocarbon free or have relatively low amounts of hydrocarbons.Conditions during formation may determine the thickness of hydrocarbonand non-hydrocarbon layers in an oil shale formation. An oil shaleformation to be subjected to in situ conversion will typically includeat least one hydrocarbon containing layer having a thickness sufficientfor economical production of formation fluids. Richness of a hydrocarboncontaining layer may be a factor used to determine if a formation willbe treated by in situ conversion. A thin and rich hydrocarbon layer maybe able to produce significantly more valuable hydrocarbons than a muchthicker, less rich hydrocarbon layer. Producing hydrocarbons from aformation that is both thick and rich is desirable.

[0541] Each hydrocarbon containing layer of a formation may have apotential formation fluid yield or richness. The richness of ahydrocarbon layer may vary in a hydrocarbon layer and between differenthydrocarbon layers in a formation. Richness may depend on many factorsincluding the conditions under which the hydrocarbon containing layerwas formed, an amount of hydrocarbons in the layer, and/or a compositionof hydrocarbons in the layer. Richness of a hydrocarbon layer may beestimated in various ways. For example, richness may be measured by aFischer Assay. The Fischer Assay is a standard method which involvesheating a sample of a hydrocarbon containing layer to approximately 500°C. in one hour, collecting products produced from the heated sample, andquantifying the amount of products produced. A sample of a hydrocarboncontaining layer may be obtained from an oil shale formation by a methodsuch as coring or any other sample retrieval method.

[0542] An in situ conversion process may be used to treat formationswith hydrocarbon layers that have thicknesses greater than about 10 m.Thick formations may allow for placement of heat sources so thatsuperposition of heat from the heat sources efficiently heats theformation to a desired temperature. Formations having hydrocarbon layersthat are less than 10 m thick may also be treated using an in situconversion process. In some in situ conversion embodiments of thinhydrocarbon layer formations, heat sources may be inserted in oradjacent to the hydrocarbon layer along a length of the hydrocarbonlayer (e.g., with horizontal or directional drilling). Heat losses tolayers above and below the thin hydrocarbon layer or thin hydrocarbonlayers may be offset by an amount and/or quality of fluid produced fromthe formation.

[0543]FIG. 3 shows a schematic view of an embodiment of a portion of anin situ conversion system for treating an oil shale formation. Heatsources 100 may be placed within at least a portion of the oil shaleformation. Heat sources 100 may include, for example, electric heaterssuch as insulated conductors, conductor-in-conduit heaters, surfaceburners, flameless distributed combustors, and/or natural distributedcombustors. Heat sources 100 may also include other types of heaters.Heat sources 100 may provide heat to at least a portion of an oil shaleformation. Energy may be supplied to the heat sources 100 through supplylines 102. The supply lines may be structurally different depending onthe type of heat source or heat sources being used to heat theformation. Supply lines for heat sources may transmit electricity forelectric heaters, may transport fuel for combustors, or may transportheat exchange fluid that is circulated within the formation.

[0544] Production wells 104 may be used to remove formation fluid fromthe formation. Formation fluid produced from production wells 104 may betransported through collection piping 106 to treatment facilities 108.Formation fluids may also be produced from heat sources 100. Forexample, fluid may be produced from heat sources 100 to control pressurewithin the formation adjacent to the heat sources. Fluid produced fromheat sources 100 may be transported through tubing or piping tocollection piping 106 or the produced fluid may be transported throughtubing or piping directly to treatment facilities 108. Treatmentfacilities 108 may include separation units, reaction units, upgradingunits, fuel cells, turbines, storage vessels, and other systems andunits for processing produced formation fluids.

[0545] An in situ conversion system for treating hydrocarbons mayinclude dewatering wells 110 (wells shown with reference number 110 may,in some embodiments, be capture, barrier, and/or isolation wells).Dewatering wells 110 or vacuum wells may remove liquid water and/orinhibit liquid water from entering a portion of an oil shale formationto be heated, or to a formation being heated. A plurality of water wellsmay surround all or a portion of a formation to be heated. In theembodiment depicted in FIG. 3, dewatering wells 110 are shown extendingonly along one side of heat sources 100, but dewatering wells typicallyencircle all heat sources 100 used, or to be used, to heat theformation.

[0546] Dewatering wells 110 may be placed in one or more ringssurrounding selected portions of the formation. New dewatering wells mayneed to be installed as an area being treated by the in situ conversionprocess expands. An outermost row of dewatering wells may inhibit asignificant amount of water from flowing into the portion of formationthat is heated or to be heated. Water produced from the outermost row ofdewatering wells should be substantially clean, and may require littleor no treatment before being released. An innermost row of dewateringwells may inhibit water that bypasses the outermost row from flowinginto the portion of formation that is heated or to be heated. Theinnermost row of dewatering wells may also inhibit outward migration ofvapor from a heated portion of the formation into surrounding portionsof the formation. Water produced by the innermost row of dewateringwells may include some hydrocarbons. The water may need to be treatedbefore being released. Alternately, water with hydrocarbons may bestored and used to produce synthesis gas from a portion of the formationduring a synthesis gas phase of the in situ conversion process. Thedewatering wells may reduce heat loss to surrounding portions of theformation, may increase production of vapors from the heated portion,and/or may inhibit contamination of a water table proximate the heatedportion of the formation.

[0547] In some embodiments, pressure differences between successive rowsof dewatering wells may be minimized (e.g., maintained relatively low ornear zero) to create a “no or low flow” boundary between rows.

[0548] In some in situ conversion process embodiments, a fluid may beinjected in the innermost row of wells. The injected fluid may maintaina sufficient pressure around a pyrolysis zone to inhibit migration offluid from the pyrolysis zone through the formation. The fluid may actas an isolation barrier between the outermost wells and the pyrolysisfluids. The fluid may improve the efficiency of the dewatering wells.

[0549] In certain embodiments, wells initially used for one purpose maybe later used for one or more other purposes, thereby lowering projectcosts and/or decreasing the time required to perform certain tasks. Forinstance, production wells (and in some circumstances heater wells) mayinitially be used as dewatering wells (e.g., before heating is begunand/or when heating is initially started). In addition, in somecircumstances dewatering wells can later be used as production wells(and in some circumstances heater wells). As such, the dewatering wellsmay be placed and/or designed so that such wells can be later used asproduction wells and/or heater wells. The heater wells may be placedand/or designed so that such wells can be later used as production wellsand/or dewatering wells. The production wells may be placed and/ordesigned so that such wells can be later used as dewatering wells and/orheater wells. Similarly, injection wells may be wells that initiallywere used for other purposes (e.g., heating, production, dewatering,monitoring, etc.), and injection wells may later be used for otherpurposes. Similarly, monitoring wells may be wells that initially wereused for other purposes (e.g., heating, production, dewatering,injection, etc.), and monitoring wells may later be used for otherpurposes.

[0550] Hydrocarbons to be subjected to in situ conversion may be locatedunder a large area. The in situ conversion system may be used to treatsmall portions of the formation, and other sections of the formation maybe treated as time progresses. In an embodiment of a system for treatinga formation (e.g., an oil shale formation), a field layout for 24 yearsof development may be divided into 24 individual plots that representindividual drilling years. Each plot may include 120 “tiles” (repeatingmatrix patterns) wherein each plot is made of 6 rows by 20 columns oftiles. Each tile may include 1 production well and 12 or 18 heaterwells. The heater wells may be placed in an equilateral triangle patternwith a well spacing of about 12 m. Production wells may be located incenters of equilateral triangles of heater wells, or the productionwells may be located approximately at a midpoint between two adjacentheater wells.

[0551] In certain embodiments, heat sources will be placed within aheater well formed within an oil shale formation. The heater well mayinclude an opening through an overburden of the formation. The heatermay extend into or through at least one hydrocarbon containing section(or hydrocarbon containing layer) of the formation. As shown in FIG. 4,an embodiment of heater well 224 may include an opening in hydrocarbonlayer 222 that has a helical or spiral shape. A spiral heater well mayincrease contact with the formation as opposed to a verticallypositioned heater. A spiral heater well may provide expansion room thatinhibits buckling or other modes of failure when the heater well isheated or cooled. In some embodiments, heater wells may includesubstantially straight sections through overburden 220. Use of astraight section of heater well through the overburden may decrease heatloss to the overburden and reduce the cost of the heater well.

[0552] As shown in FIG. 5, a heat source embodiment may be placed intoheater well 224. Heater well 224 may be substantially “U” shaped. Thelegs of the “U” may be wider or more narrow depending on the particularheater well and formation characteristics. First portion 226 and thirdportion 228 of heater well 224 may be arranged substantiallyperpendicular to an upper surface of hydrocarbon layer 222 in someembodiments. In addition, the first and the third portion of the heaterwell may extend substantially vertically through overburden 220. Secondportion 230 of heater well 224 may be substantially parallel to theupper surface of the hydrocarbon layer.

[0553] Multiple heat sources (e.g., 2, 3, 4, 5, 10 heat sources or more)may extend from a heater well in some situations. As shown in FIG. 6,heat sources 232, 234, and 236 extend through overburden 220 intohydrocarbon layer 222 from heater well 224. Multiple wells extendingfrom a single wellbore may be used when surface considerations (e.g.,aesthetics, surface land use concerns, and/or unfavorable soilconditions near the surface) make it desirable to concentrate wellplatforms in a small area. For example, in areas where the soil isfrozen and/or marshy, it may be more cost-effective to have a minimalnumber of well platforms located at selected sites.

[0554] In certain embodiments, a first portion of a heater well mayextend from the ground surface, through an overburden, and into an oilshale formation. A second portion of the heater well may include one ormore heater wells in the oil shale formation. The one or more heaterwells may be disposed within the oil shale formation at various angles.In some embodiments, at least one of the heater wells may be disposedsubstantially parallel to a boundary of the oil shale formation. Inalternate embodiments, at least one of the heater wells may besubstantially perpendicular to the oil shale formation. In addition, oneof the one or more heater wells may be positioned at an angle betweenperpendicular and parallel to a layer in the formation.

[0555]FIG. 7 illustrates a schematic of view of multilateral or sidetracked lateral heaters branched from a single well in an oil shaleformation. In relatively thin and deep layers found in an oil shaleformation, it may be advantageous to place more than one heatersubstantially horizontally within the relatively thin layer ofhydrocarbons. For example, an oil shale layer may have a richnessgreater than about 0.06 L/kg and a relatively low initial thermalconductivity. Heat provided to a thin layer with a low thermalconductivity from a horizontal wellbore may be more effectively trappedwithin the thin layer and reduce heat losses from the layer.Substantially vertical opening 6108 may be placed in hydrocarbon layer6100. Substantially vertical opening 6108 may be an elongated portion ofan opening formed in hydrocarbon layer 6100. Hydrocarbon layer 6100 maybe below overburden 540.

[0556] One or more substantially horizontal openings 6102 may also beplaced in hydrocarbon layer 6100. Horizontal openings 6102 may, in someembodiments, contain perforated liners. The horizontal openings 6102 maybe coupled to vertical opening 6108. Horizontal openings 6102 may beelongated portions that diverge from the elongated portion of verticalopening 6108. Horizontal openings 6102 may be formed in hydrocarbonlayer 6100 after vertical opening 6108 has been formed. In certainembodiments, openings 6102 may be angled upwards to facilitate flow offormation fluids towards the production conduit.

[0557] Each horizontal opening 6102 may lie above or below an adjacenthorizontal opening. In an embodiment, six horizontal openings 6102 maybe formed in hydrocarbon layer 6100. Three horizontal openings 6102 mayface 180°, or in a substantially opposite direction, from threeadditional horizontal openings 6102. Two horizontal openings facingsubstantially opposite directions may lie in a substantially identicalvertical plane within the formation. Any number of horizontal openings6102 may be coupled to a single vertical opening 6108, depending on, butnot limited to, a thickness of hydrocarbon layer 6100, a type offormation, a desired heating rate in the formation, and a desiredproduction rate.

[0558] Production conduit 6106 may be placed substantially verticallywithin vertical opening 6108. Production conduit 6106 may besubstantially centered within vertical opening 6108. Pump 6107 may becoupled to production conduit 6106. Such pump may be used, in someembodiments, to pump formation fluids from the bottom of the well. Pump6107 may be a rod pump, progressing cavity pump (PCP), centrifugal pump,jet pump, gas lift pump, submersible pump, rotary pump, etc.

[0559] One or more heaters 6104 may be placed within each horizontalopening 6102. Heaters 6104 may be placed in hydrocarbon layer 6100through vertical opening 6108 and into horizontal opening 6102.

[0560] In some embodiments, heater 6104 may be used to generate heatalong a length of the heater within vertical opening 6108 and horizontalopening 6102. In other embodiments, heater 6104 may be used to generateheat only within horizontal opening 6102. In certain embodiments, heatgenerated by heater 6104 may be varied along its length and/or variedbetween vertical opening 6108 and horizontal opening 6102. For example,less heat may be generated by heater 6104 in vertical opening 6108 andmore heat may be generated by the heater in horizontal opening 6102. Itmay be advantageous to have at least some heating within verticalopening 6108. This may maintain fluids produced from the formation in avapor phase in production conduit 6106 and/or may upgrade the producedfluids within the production well. Having production conduit 6106 andheaters 6104 installed into a formation through a single opening in theformation may reduce costs associated with forming openings in theformation and installing production equipment and heaters within theformation.

[0561]FIG. 8 depicts a schematic view from an elevated position of theembodiment of FIG. 7. One or more vertical openings 6108 may be formedin hydrocarbon layer 6100. Each of vertical openings 6108 may lie alonga single plane in hydrocarbon layer 6100. Horizontal openings 6102 mayextend in a plane substantially perpendicular to the plane of verticalopenings 6108. Additional horizontal openings 6102 may lie in a planebelow the horizontal openings as shown in the schematic depiction ofFIG. 7. A number of vertical openings 6108 and/or a spacing betweenvertical openings 6108 may be determined by, for example, a desiredheating rate or a desired production rate. In some embodiments, spacingbetween vertical openings may be about 4 m to about 30 m. Longer orshorter spacings may be used to meet specific formation needs. A lengthof a horizontal opening 6102 may be up to about 1600 m. However, alength of horizontal openings 6102 may vary depending on, for example, amaximum installation cost, an area of hydrocarbon layer 6100, or amaximum producible heater length.

[0562] In an in situ conversion process embodiment, a formation havingone or more thin hydrocarbon layers may be treated. The hydrocarbonlayer may be, but is not limited to, a rich, thin oil shale. In some insitu conversion process embodiments, such formations may be treated withheat sources that are positioned substantially horizontal within and/oradjacent to the thin hydrocarbon layer or thin hydrocarbon layers. Arelatively thin hydrocarbon layer may be at a substantial depth below aground surface. For example, a formation may have an overburden of up toabout 650 m in depth. The cost of drilling a large number ofsubstantially vertical wells within a formation to a significant depthmay be expensive. It may be advantageous to place heaters horizontallywithin these formations to heat large portions of the formation forlengths up to about 1600 m. Using horizontal heaters may reduce thenumber of vertical wells that are needed to place a sufficient number ofheaters within the formation.

[0563]FIG. 9 illustrates an embodiment of hydrocarbon containing layer200 that may be at a near-horizontal angle with respect to an uppersurface of ground 204. An angle of hydrocarbon containing layer 200,however, may vary. For example, hydrocarbon containing layer 200 may dipor be steeply dipping. Economically viable production of a steeplydipping hydrocarbon containing layer may not be possible using presentlyavailable mining methods.

[0564] A dipping or relatively steeply dipping hydrocarbon containinglayer may be subjected to an in situ conversion process. For example, aset of production wells may be disposed near a highest portion of adipping hydrocarbon layer of an oil shale formation. Hydrocarbonportions adjacent to and below the production wells may be heated topyrolysis temperature. Pyrolysis fluid may be produced from theproduction wells. As production from the top portion declines, deeperportions of the formation may be heated to pyrolysis temperatures.Vapors may be produced from the hydrocarbon containing layer bytransporting vapor through the previously pyrolyzed hydrocarbons. Highpermeability resulting from pyrolysis and production of fluid from theupper portion of the formation may allow for vapor phase transport withminimal pressure loss. Vapor phase transport of fluids produced in theformation may eliminate a need to have deep production wells in additionto the set of production wells. A number of production wells required toprocess the formation may be reduced. Reducing the number of productionwells required for production may increase economic viability of an insitu conversion process.

[0565] In steeply dipping formations, directional drilling may be usedto form an opening in the formation for a heater well or productionwell. Directional drilling may include drilling an opening in which theroute/course of the opening may be planned before drilling. Such anopening may usually be drilled with rotary equipment. In directionaldrilling, a route/course of an opening may be controlled by deflectionwedges, etc.

[0566] A wellbore may be formed using a drill equipped with a steerablemotor and an accelerometer. The steerable motor and accelerometer mayallow the wellbore to follow a layer in the oil shale formation. Asteerable motor may maintain a substantially constant distance betweenheater well 202 and a boundary of hydrocarbon containing layer 200throughout drilling of the opening.

[0567] In some in situ conversion embodiments, geosteered drilling maybe used to drill a wellbore in an oil shale formation. Geosteereddrilling may include determining or estimating a distance from an edgeof hydrocarbon containing layer 200 to the wellbore with a sensor. Thesensor may monitor variations in characteristics or signals in theformation. The characteristic or signal variance may allow fordetermination of a desired drill path. The sensor may monitorresistance, acoustic signals, magnetic signals, gamma rays, and/or othersignals within the formation. A drilling apparatus for geosteereddrilling may include a steerable motor. The steerable motor may becontrolled to maintain a predetermined distance from an edge of ahydrocarbon containing layer based on data collected by the sensor.

[0568] In some in situ conversion embodiments, wellbores may be formedin a formation using other techniques. Wellbores may be formed byimpaction techniques and/or by sonic drilling techniques. The methodused to form wellbores may be determined based on a number of factors.The factors may include, but are not limited to, accessibility of thesite, depth of the wellbore, properties of the overburden, andproperties of the hydrocarbon containing layer or layers.

[0569]FIG. 10 illustrates an embodiment of a plurality of heater wells210 formed in hydrocarbon layer 212. Hydrocarbon layer 212 may be asteeply dipping layer. One or more of heater wells 210 may be formed inthe formation such that two or more of the heater wells aresubstantially parallel to each other, and/or such that at least oneheater well is substantially parallel to a boundary of hydrocarbon layer212. For example, one or more of heater wells 210 may be formed inhydrocarbon layer 212 by a magnetic steering method. An example of amagnetic steering method is illustrated in U.S. Pat. No. 5,676,212 toKuckes, which is incorporated by reference as if fully set forth herein.Magnetic steering may include drilling heater well 210 parallel to anadjacent heater well. The adjacent well may have been previouslydrilled. In addition, magnetic steering may include directing thedrilling by sensing and/or determining a magnetic field produced in anadjacent heater well. For example, the magnetic field may be produced inthe adjacent heater well by flowing a current through an insulatedcurrent-carrying wireline disposed in the adjacent heater well.

[0570] Magnetic steering may include directing the drilling by sensingand/or determining a magnetic field produced in an adjacent well. Forexample, the magnetic field may be produced in the adjacent well byflowing a current through an insulated current-carrying wirelinedisposed in the adjacent well. In some embodiments, magnetostaticsteering may be used to form openings adjacent to a first opening. U.S.Pat. No. 5,541,517, issued to Hartmann et al., which is incorporated byreference as if fully set forth herein, describes a method for drillinga wellbore relative to a second wellbore that has magnetized casingportions.

[0571] When drilling a wellbore (opening), a magnet or magnets may beinserted into a first opening to provide a magnetic field used to guidea drilling mechanism that forms an adjacent opening or adjacentopenings. The magnetic field may be detected by a 3-axis fluxgatemagnetometer in the opening being drilled. A control system may useinformation detected by the magnetometer to determine and implementoperation parameters needed to form an opening that is a selecteddistance away (e.g., parallel) from the first opening (within desiredtolerances). Some types of wells may require or need close tolerances.For example, freeze wells may need to be positioned parallel to eachother with small or no variance in parallel alignment to allow forformation of a continuous frozen barrier around a treatment area. Also,vertical and/or horizontally positioned heater wells and/or productionwells may need to be positioned parallel to each other with small or novariance in parallel alignment to allow for substantially uniformheating and/or production from a treatment area in a formation.

[0572]FIG. 11 depicts a schematic representation of an embodiment of amagnetostatic drilling operation to form an opening that is a selecteddistance away from (e.g., substantially parallel to) a drilled opening.Opening 514 may be formed in formation 6100. Opening 514 may be a casedopening or an open hole opening. Magnetic string 9678 may be insertedinto opening 514. Magnetic string 9678 may be unwound from a reel intoopening 514. In an embodiment, magnetic string includes several segments9680 of magnets within casing 6152.

[0573] In some embodiments, casing 6152 may be a conduit made of amaterial that is not significantly influenced by a magnetic field (e.g.,non-magnetic alloy such as non-magnetic stainless steel (e.g., 304, 310,316 stainless steel), reinforced polymer pipe, or brass tubing). Thecasing may be a conduit of a conductor-in-conduit heater, or it may beperforated liner or casing. If the casing is not significantlyinfluenced by a magnetic field, then the magnetic flux will not beshielded. In other embodiments, the casing may be made of a materialthat is influenced by a magnetic field (e.g., carbon steel). The use ofa material that is influenced by a magnetic field may weaken thestrength of the magnetic field to be detected by drilling apparatus 9684in adjacent opening 9685.

[0574] Magnets may be inserted in conduits 9681 in segments 9680.Conduits 9681 may be threaded or seamless coiled tubing (e.g., tubinghaving an inside diameter of about 5 cm). Members 9682 (e.g., pins) maybe placed between segments 9680 to inhibit movement of segments 9680relative to conduit 9681. Magnets from adjoining segments of conduit maybe close to each other or touch each other as, for example, threadedsections of conduit are tightened together. A segment may be made ofseveral north-south aligned magnets. Alignment of the magnets allowseach segment to effectively be a long magnet. In an embodiment, asegment may include one magnet. Magnets may be Alnico magnets or othertypes of magnets having significant magnetic strength. Two adjacentsegments may be oriented to have opposite polarities so that thesegments repel each other.

[0575] The magnetic string may include 2 or more magnetic segments.Segments may range in length from about 1.5 m to about 15 m. Magneticsegments may be formed from several magnets. Magnets used to formsegments may have diameters greater than about 1 cm (about 4.5 cm). Themagnets may be oriented so that the magnets are attracted to each other.For example, a segment may be made of 40 magnets each having a length ofabout 0.15 m.

[0576]FIG. 12 depicts a schematic of a portion of magnetic string.Segments 9680 may be positioned such that adjacent segments 9680 haveopposing polarities. In some embodiments, force may be applied tominimize distance 9692 between segments 9680. Additional segments may beadded to increase a length of magnetic string 9678. Magnetic strings maybe coiled after assembling. Installation of the magnetic string mayinclude uncoiling the magnetic string.

[0577] For example, first segment 9697 may be positioned north-south inthe conduit and second segment 9698 may be positioned south-north suchthat the south poles of segments 9697, 9698 are proximate each other.Third segment 9696 may positioned in the conduit may be positioned in anorth-south orientation such that the north poles of segments 9697, 9696are proximate each other. Magnet strings may include multiplesouth-south and north-north interfaces. As shown in FIG. 12, thisconfiguration may induce a series of magnetic fields 9694.

[0578] Alternating the polarity of the segments within a magnetic stringmay provide several magnetic field differentials that allow forreduction in the amount of deviation that is a selected distance betweenthe openings. Increasing a length of the segments within the magneticstring may increase the radial distance at which the magnetometer maydetect a magnetic field. In some embodiments, the length of segmentswithin the magnetic string may be varied. For example, more magnets maybe used in the segment proximate the earth's surface than in segmentspositioned in the formation.

[0579] In an embodiment, when the separation distance between twowellbores increases, then the segment length of the magnetic strings mayalso be increased, and vice versa. With shorter segment lengths, whilethe overall strength of the magnetic field is decreased, variations inthe magnetic field occur more frequently, thus providing more guidanceto the drilling operation. For example, segments having a length ofabout 6 m may induce a magnetic field sufficient to allow drilling ofadjacent openings at distances of less than about 16 m. Thisconfiguration may allow a desired tolerance between the adjacentopenings to be achieved.

[0580] In alternate embodiments, the strength of the magnets used mayaffect a strength of the magnetic field induced. For example, when usingmagnets having a lower strength than those in the example above, asegment length of about 6 m may induce a magnetic field sufficient todrill adjacent openings at distances of less than about 6 m. In someembodiments, a segment length of about 6 m may induce a magnetic fieldsufficient to drill adjacent openings at distances of less than about 10m.

[0581] A length of the magnetic string may be based on an economicbalance between cost of the string and the cost of having to repositionthe string during drilling. A string length may range from about 30 m toabout 500 m. In an embodiment, a magnetic string may have a length ofabout 150 m. Thus, in some embodiments, the magnetic string may need tobe repositioned if the openings being drilled are longer than the lengthof the string.

[0582] When multiple wellbores are to be drilled, it is possible toinitially drill a center wellbore, and then use magnetic strings in thatcenter wellbore to guide the drilling of the other wellboressubstantially surrounding the center wellbore. In this manner cumulativeerrors may be limited since, for example, movement of the magneticstring may be minimized. In addition, only the center well in thisembodiment will include a more expensive nonmagnetic liner.

[0583] In some embodiments, heated portion 310 may extend radially fromheat source 300, as shown in FIG. 13. For example, a width of heatedportion 310, in a direction extending radially from heat source 300, maybe about 0 m to about 10 m. A width of heated portion 310 may vary,however, depending upon, for example, heat provided by heat source 300and the characteristics of the formation. Heat provided by heat source300 will typically transfer through the heated portion to create atemperature gradient within the heated portion. For example, atemperature proximate the heater well will generally be higher than atemperature proximate an outer lateral boundary of the heated portion. Atemperature gradient within the heated portion may vary within theheated portion depending on various factors (e.g., thermal conductivityof the formation, density, and porosity).

[0584] As heat transfers through heated portion 310 of the oil shaleformation, a temperature within at least a section of the heated portionmay be within a pyrolysis temperature range. As the heat transfers awayfrom the heat source, a front at which pyrolysis occurs will in manyinstances travel outward from the heat source. For example, heat fromthe heat source may be allowed to transfer into a selected section ofthe heated portion such that heat from the heat source pyrolyzes atleast some of the hydrocarbons within the selected section. Pyrolysismay occur within selected section 315 of the heated portion, andpyrolyzation fluids will be generated in the selected section.

[0585] Selected section 315 may have a width radially extending from theinner lateral boundary of the selected section. For a single heat sourceas depicted in FIG. 13, width of the selected section may be dependenton a number of factors. The factors may include, but are not limited to,time that heat source 300 is supplying energy to the formation, thermalconductivity properties of the formation, extent of pyrolyzation ofhydrocarbons in the formation. A width of selected section 315 mayexpand for a significant time after initialization of heat source 300. Awidth of selected section 315 may initially be zero and may expand to 10m or more after initialization of heat source 300.

[0586] An inner boundary of selected section 315 may be radially spacedfrom the heat source. The inner boundary may define a volume of spenthydrocarbons 317. Spent hydrocarbons 317 may include a volume ofhydrocarbon material that is transformed to coke due to the proximityand heat of heat source 300. Coking may occur by pyrolysis reactionsthat occur due to a rapid increase in temperature in a short timeperiod. Applying heat to a formation at a controlled rate may allow foravoidance of significant coking, however, some coking may occur in thevicinity of heat sources. Spent hydrocarbons 317 may also include avolume of material that has been subjected to pyrolysis and the removalof pyrolysis fluids. The volume of material that has been subjected topyrolysis and the removal of pyrolysis fluids may produce insignificantamounts or no additional pyrolysis fluids with increases in temperature.The inner lateral boundary may advance radially outwards as timeprogresses during operation of an in situ conversion process.

[0587] In some embodiments, a plurality of heated portions may existwithin a unit of heat sources. A unit of heat sources refers to aminimal number of heat sources that form a template that is repeated tocreate a pattern of heat sources within the formation. The heat sourcesmay be located within the formation such that superposition(overlapping) of heat produced from the heat sources occurs. Forexample, as illustrated in FIG. 14, transfer of heat from two or moreheat sources 330 results in superposition of heat to region 332 betweenthe heat sources 330. Superposition of heat may occur between two,three, four, five, six, or more heat sources. Region 332 is an area inwhich temperature is influenced by various heat sources. Superpositionof heat may provide the ability to efficiently raise the temperature oflarge volumes of a formation to pyrolysis temperatures. The size ofregion 332 may be significantly affected by the spacing between heatsources.

[0588] Superposition of heat may increase a temperature in at least aportion of the formation to a temperature sufficient for pyrolysis ofhydrocarbons within the portion. Superposition of heat to region 332 mayincrease the quantity of hydrocarbons in a formation that are subjectedto pyrolysis. Selected sections of a formation that are subjected topyrolysis may include regions 334 brought into a pyrolysis temperaturerange by heat transfer from substantially only one heat source. Selectedsections of a formation that are subjected to pyrolysis may also includeregions 332 brought into a pyrolysis temperature range by superpositionof heat from multiple heat sources.

[0589] A pattern of heat sources will often include many units of heatsources. There will typically be many heated portions, as well as manyselected sections within the pattern of heat sources. Superposition ofheat within a pattern of heat sources may decrease the time necessary toreach pyrolysis temperatures within the multitude of heated portions.Superposition of heat may allow for a relatively large spacing betweenadjacent heat sources. In some embodiments, a large spacing may providefor a relatively slow heating rate of hydrocarbon material. The slowheating rate may allow for pyrolysis of hydrocarbon material withminimal coking or no coking within the formation away from areas in thevicinity of the heat sources. Heating from heat sources allows theselected section to reach pyrolysis temperatures so that allhydrocarbons within the selected section may be subject to pyrolysisreactions. In some in situ conversion embodiments, a majority ofpyrolysis fluids are produced when the selected section is within arange from about 0 m to about 25 m from a heat source.

[0590] In an in situ conversion process embodiment, a heating rate maybe controlled to minimize costs associated with heating a selectedsection. The costs may include, for example, input energy costs andequipment costs. In certain embodiments, a cost associated with heatinga selected section may be minimized by reducing a heating rate when thecost associated with heating is relatively high and increasing theheating rate when the cost associated with heating is relatively low.For example, a heating rate of about 330 watts/m may be used when theassociated cost is relatively high, and a heating rate of about 1640watts/m may be used when the associated cost is relatively low. The costassociated with heating may be relatively high at peak times of energyuse, such as during the daytime. For example, energy use may be high inwarm climates during the daytime in the summer due to energy use for airconditioning. Low times of energy use may be, for example, at night orduring weekends, when energy demand tends to be lower. In an embodiment,the heating rate may be varied from a higher heating rate during lowenergy usage times, such as during the night, to a lower heating rateduring high energy usage times, such as during the day.

[0591] As shown in FIG. 3, in addition to heat sources 100, one or moreproduction wells 104 will typically be placed within the portion of theoil shale formation. Formation fluids may be produced through productionwell 104. In some embodiments, production well 104 may include a heatsource. The heat source may heat the portions of the formation at ornear the production well and allow for vapor phase removal of formationfluids. The need for high temperature pumping of liquids from theproduction well may be reduced or eliminated. Avoiding or limiting hightemperature pumping of liquids may significantly decrease productioncosts. Providing heating at or through the production well may: (1)inhibit condensation and/or refluxing of production fluid when suchproduction fluid is moving in the production well proximate theoverburden, (2) increase heat input into the formation, and/or (3)increase formation permeability at or proximate the production well. Insome in situ conversion process embodiments, an amount of heat suppliedto production wells is significantly less than an amount of heat appliedto heat sources that heat the formation.

[0592] Because permeability and/or porosity increases in the heatedformation, produced vapors may flow considerable distances through theformation with relatively little pressure differential. Increases inpermeability may result from a reduction of mass of the heated portiondue to vaporization of water, removal of hydrocarbons, and/or creationof fractures. Fluids may flow more easily through the heated portion. Insome embodiments, production wells may be provided in upper portions ofhydrocarbon layers. As shown in FIG. 9, production wells 206 may extendinto an oil shale formation near the top of heated portion 208.Extending production wells significantly into the depth of the heatedhydrocarbon layer may be unnecessary.

[0593] Fluid generated within an oil shale formation may move aconsiderable distance through the oil shale formation as a vapor. Theconsiderable distance may be over 1000 m depending on various factors(e.g., permeability of the formation, properties of the fluid,temperature of the formation, and pressure gradient allowing movement ofthe fluid). Due to increased permeability in formations subjected to insitu conversion and formation fluid removal, production wells may onlyneed to be provided in every other unit of heat sources or every third,fourth, fifth, or sixth units of heat sources.

[0594] Embodiments of a production well may include valves that alter,maintain, and/or control a pressure of at least a portion of theformation. Production wells may be cased wells. Production wells mayhave production screens or perforated casings adjacent to productionzones. In addition, the production wells may be surrounded by sand,gravel or other packing materials adjacent to production zones.Production wells 104 may be coupled to treatment facilities 108, asshown in FIG. 3.

[0595] During an in situ process, production wells may be operated suchthat the production wells are at a lower pressure than other portions ofthe formation. In some embodiments, a vacuum may be drawn at theproduction wells. Maintaining the production wells at lower pressuresmay inhibit fluids in the formation from migrating outside of the insitu treatment area.

[0596]FIG. 15 illustrates an embodiment of production well 6108 placedin hydrocarbon layer 6100. Production well 6108 may be used to produceformation fluids from hydrocarbon layer 6100. Hydrocarbon layer 6100 maybe treated using an in situ conversion process. Production conduit 6106may be placed within production well 6108. In an embodiment, productionconduit 6106 is a hollow sucker rod placed in production well 6108.Production well 6108 may have a casing, or lining, placed along thelength of the production well. The casing may have openings, orperforations, to allow formation fluids to enter production well 6108.Formation fluids may include vapors and/or liquids. Production conduit6106 and production well 6108 may include non-corrosive materials suchas steel.

[0597] In certain embodiments, production conduit 6106 may include heatsource 6105. Heat source 6105 may be a heater placed inside or outsideproduction conduit 6106 or formed as part of the production conduit.Heat source 6105 may be a heater such as an insulated conductor heater,a conductor-in-conduit heater, or a skin-effect heater. A skin-effectheater is an electric heater that uses eddy current heating to induceresistive losses in production conduit 6106 to heat the productionconduit. An example of a skin-effect heater is obtainable from DagangOil Products (China).

[0598] Heating of production conduit 6106 may inhibit condensationand/or refluxing in the production conduit or within production well6108. In certain embodiments, heating of production conduit 6106 mayinhibit plugging of pump 6107 by liquids (e.g., heavy hydrocarbons). Forexample, heat source 6105 may heat production conduit 6106 to about 35°C. to maintain the mobility of liquids in the production conduit toinhibit plugging of pump 6107 or the production conduit. In certainembodiments (e.g., for formations greater than about 100 m in depth),heat source 6105 may heat production conduit 6106 and/or production well6108 to temperatures of about 200° C. to about 250° C. to maintainproduced fluids substantially in a vapor phase by inhibitingcondensation and/or reflux of fluids in the production well.

[0599] Pump 6107 may be coupled to production conduit 6106. Pump 6107may be used to pump formation fluids from hydrocarbon layer 6100 intoproduction conduit 6106. Pump 6107 may be any pump used to pump fluids,such as a rod pump, PCP, jet pump, gas lift pump, centrifugal pump,rotary pump, or submersible pump. Pump 6107 may be used to pump fluidsthrough production conduit 6106 to a surface of the formation aboveoverburden 540.

[0600] In certain embodiments, pump 6107 can be used to pump formationfluids that may be liquids. Liquids may be produced from hydrocarbonlayer 6100 prior to production well 6108 being heated to a temperaturesufficient to vaporize liquids within the production well. In someembodiments, liquids produced from the formation tend to include water.Removing liquids from the formation before heating the formation, orduring early times of heating before pyrolysis occurs, tends to reducethe amount of heat input that is needed to produce hydrocarbons from theformation.

[0601] In an embodiment, formation fluids that are liquids may beproduced through production conduit 6106 using pump 6107. Formationfluids that are vapors may be simultaneously produced through an annulusof production well 6108 outside of production conduit 6106.

[0602] Insulation may be placed on a wall of production well 6108 in asection of the production well within overburden 540. The insulation maybe cement or any other suitable low heat transfer material. Insulatingthe overburden section of production well 6108 may inhibit transfer ofheat from fluids being produced from the formation into the overburden.

[0603] In an in situ conversion process embodiment, a mixture may beproduced from an oil shale formation. The mixture may be producedthrough a heater well disposed in the formation. Producing the mixturethrough the heater well may increase a production rate of the mixture ascompared to a production rate of a mixture produced through a non-heaterwell. A non-heater well may include a production well. In someembodiments, a production well may be heated to increase a productionrate.

[0604] A heated production well may inhibit condensation of highercarbon numbers (C₅ or above) in the production well. A heated productionwell may inhibit problems associated with producing a hot, multi-phasefluid from a formation.

[0605] A heated production well may have an improved production rate ascompared to a non-heated production well. Heat applied to the formationadjacent to the production well from the production well may increaseformation permeability adjacent to the production well by vaporizing andremoving liquid phase fluid adjacent to the production well and/or byincreasing the permeability of the formation adjacent to the productionwell by formation of macro and/or micro fractures. A heater in a lowerportion of a production well may be turned off when superposition ofheat from heat sources heats the formation sufficiently to counteractbenefits provided by heating from within the production well. In someembodiments, a heater in an upper portion of a production well mayremain on after a heater in a lower portion of the well is deactivated.The heater in the upper portion of the well may inhibit condensation andreflux of formation fluid.

[0606] In some embodiments, heated production wells may improve productquality by causing production through a hot zone in the formationadjacent to the heated production well. A final phase of thermalcracking may exist in the hot zone adjacent to the production well.Producing through a hot zone adjacent to a heated production well mayallow for an increased olefin content in non-condensable hydrocarbonsand/or condensable hydrocarbons in the formation fluids. The hot zonemay produce formation fluids with a greater percentage ofnon-condensable hydrocarbons due to thermal cracking in the hot zone.The extent of thermal cracking may depend on a temperature of the hotzone and/or on a residence time in the hot zone. A heater can bedeliberately run hotter to promote the further in situ upgrading ofhydrocarbons.

[0607] In an embodiment, heating in or proximate a production well maybe controlled such that a desired mixture is produced through theproduction well. The desired mixture may have a selected yield ofnon-condensable hydrocarbons. For example, the selected yield ofnon-condensable hydrocarbons may be about 75 weight % non-condensablehydrocarbons or, in some embodiments, about 50 weight % to about 100weight %. In other embodiments, the desired mixture may have a selectedyield of condensable hydrocarbons. The selected yield of condensablehydrocarbons may be about 75 weight % condensable hydrocarbons or, insome embodiments, about 50 weight % to about 95 weight %.

[0608] A temperature and a pressure may be controlled within theformation to inhibit the production of carbon dioxide and increaseproduction of carbon monoxide and molecular hydrogen during synthesisgas production. In an embodiment, the mixture is produced through aproduction well (or heater well), which may be heated to inhibit theproduction of carbon dioxide. In some embodiments, a mixture producedfrom a first portion of the formation may be recycled into a secondportion of the formation to inhibit the production of carbon dioxide.The mixture produced from the first portion may be at a lowertemperature than the mixture produced from the second portion of theformation.

[0609] A desired volume ratio of molecular hydrogen to carbon monoxidein synthesis gas may be produced from the formation. The desired volumeratio may be about 2.0:1. In an embodiment, the volume ratio may bemaintained between about 1.8:1 and 2.2:1 for synthesis gas.

[0610]FIG. 16 illustrates a pattern of heat sources 400 and productionwells 402 that may be used to treat an oil shale formation. Heat sources400 may be arranged in a unit of heat sources such as triangular pattern401. Heat sources 400, however, may be arranged in a variety of patternsincluding, but not limited to, squares, hexagons, and other polygons.The pattern may include a regular polygon to promote uniform heating ofthe formation in which the heat sources are placed. The pattern may alsobe a line drive pattern. A line drive pattern generally includes a firstlinear array of heater wells, a second linear array of heater wells, anda production well or a linear array of production wells between thefirst and second linear array of heater wells.

[0611] A distance from a node of a polygon to a centroid of the polygonis smallest for a 3-sided polygon and increases with increasing numberof sides of the polygon. The distance from a node to the centroid for anequilateral triangle is (length/2)/(square root(3)/2) or 0.5774 timesthe length. For a square, the distance from a node to the centroid is(length/2)/(square root(2)/2) or 0.7071 times the length. For a hexagon,the distance from a node to the centroid is (length/2)/(1/2) or thelength. The difference in distance between a heat source and a midpointto a second heat source (length/2) and the distance from a heat sourceto the centroid for an equilateral pattern (0.5774 times the length) issignificantly less for the equilateral triangle pattern than for anyhigher order polygon pattern. The small difference means thatsuperposition of heat may develop more rapidly and that the formationmay rise to a more uniform temperature between heat sources using anequilateral triangle pattern rather than a higher order polygon pattern.

[0612] Triangular patterns tend to provide more uniform heating to aportion of the formation in comparison to other patterns such as squaresand/or hexagons. Triangular patterns tend to provide faster heating to apredetermined temperature in comparison to other patterns such assquares or hexagons. The use of triangular patterns may result insmaller volumes of a formation being overheated. A plurality of units ofheat sources such as triangular pattern 401 may be arrangedsubstantially adjacent to each other to form a repetitive pattern ofunits over an area of the formation. For example, triangular patterns401 may be arranged substantially adjacent to each other in a repetitivepattern of units by inverting an orientation of adjacent triangles 401.Other patterns of heat sources 400 may also be arranged such thatsmaller patterns may be disposed adjacent to each other to form largerpatterns.

[0613] Production wells may be disposed in the formation in a repetitivepattern of units. In certain embodiments, production well 402 may bedisposed proximate a center of every third triangle 401 arranged in thepattern. Production well 402, however, may be disposed in every triangle401 or within just a few triangles. In some embodiments, a productionwell may be placed within every 13, 20, or 30 heater well triangles. Forexample, a ratio of heat sources in the repetitive pattern of units toproduction wells in the repetitive pattern of units may be more thanapproximately 5 (e.g., more than 6, 7, 8, or 9). In some well patternembodiments, three or more production wells may be located within anarea defined by a repetitive pattern of units. For example, as shown inFIG. 16, production wells 410 may be located within an area defined byrepetitive pattern of units 412. Production wells 410 may be located inthe formation in a unit of production wells. The location of productionwells 402, 410 within a pattern of heat sources 400 may be determinedby, for example, a desired heating rate of the oil shale formation, aheating rate of the heat sources, the type of heat sources used, thetype of oil shale formation (and its thickness), the composition of theoil shale formation, permeability of the formation, the desiredcomposition to be produced from the formation, and/or a desiredproduction rate.

[0614] One or more injection wells may be disposed within a repetitivepattern of units. For example, as shown in FIG. 16, injection wells 414may be located within an area defined by repetitive pattern of units416. Injection wells 414 may also be located in the formation in a unitof injection wells. For example, the unit of injection wells may be atriangular pattern. Injection wells 414, however, may be disposed in anyother pattern. In certain embodiments, one or more production wells andone or more injection wells may be disposed in a repetitive pattern ofunits. For example, as shown in FIG. 16, production wells 418 andinjection wells 420 may be located within an area defined by repetitivepattern of units 422. Production wells 418 may be located in theformation in a unit of production wells, which may be arranged in afirst triangular pattern. In addition, injection wells 420 may belocated within the formation in a unit of production wells, which arearranged in a second triangular pattern. The first triangular patternmay be different than the second triangular pattern. For example, areasdefined by the first and second triangular patterns may be different.

[0615] One or more monitoring wells may be disposed within a repetitivepattern of units. Monitoring wells may include one or more devices thatmeasure temperature, pressure, and/or fluid properties. In someembodiments, logging tools may be placed in monitoring well wellbores tomeasure properties within a formation. The logging tools may be moved toother monitoring well wellbores as needed. The monitoring well wellboresmay be cased or uncased wellbores. As shown in FIG. 16, monitoring wells424 may be located within an area defined by repetitive pattern of units426. Monitoring wells 424 may be located in the formation in a unit ofmonitoring wells, which may be arranged in a triangular pattern.Monitoring wells 424, however, may be disposed in any of the otherpatterns within repetitive pattern of units 426.

[0616] It is to be understood that a geometrical pattern of heat sources400 and production wells 402 is described herein by example. A patternof heat sources and production wells will in many instances varydepending on, for example, the type of oil shale formation to betreated. For example, for relatively thin layers, heater wells may bealigned along one or more layers along strike or along dip. Forrelatively thick layers, heat sources may be at an angle to one or morelayers (e.g., orthogonally or diagonally).

[0617] A triangular pattern of heat sources may treat a hydrocarbonlayer having a thickness of about 10 m or more. For a thin hydrocarbonlayer (e.g., about 10 m thick or less) a line and/or staggered linepattern of heat sources may treat the hydrocarbon layer.

[0618] For certain thin layers, heating wells may be placed close to anedge of the layer (e.g., in a staggered line instead of a line placed inthe center of the layer) to increase the amount of hydrocarbons producedper unit of energy input. A portion of input heating energy may heatnon-hydrocarbon portions of the formation, but the staggered pattern mayallow superposition of heat to heat a majority of the hydrocarbon layersto pyrolysis temperatures. If the thin formation is heated by placingone or more heater wells in the layer along a center of the thickness, asignificant portion of the hydrocarbon layers may not be heated topyrolysis temperatures. In some embodiments, placing heater wells closerto an edge of the layer may increase the volume of layer undergoingpyrolysis per unit of energy input.

[0619] Exact placement of heater wells, production wells, etc. willdepend on variables specific to the formation (e.g., thickness of thelayer or composition of the layer), project economics, etc. In certainembodiments, heater wells may be substantially horizontal whileproduction wells may be vertical, or vice versa. In some embodiments,wells may be aligned along dip or strike or oriented at an angle betweendip and strike.

[0620] The spacing between heat sources may vary depending on a numberof factors. The factors may include, but are not limited to, the type ofan oil shale formation, the selected heating rate, and/or the selectedaverage temperature to be obtained within the heated portion. In somewell pattern embodiments, the spacing between heat sources may be withina range of about 5 m to about 25 m. In some well pattern embodiments,spacing between heat sources may be within a range of about 8 m to about15 m.

[0621] The spacing between heat sources may influence the composition offluids produced from an oil shale formation. In an embodiment, acomputer-implemented simulation may be used to determine optimum heatsource spacings within an oil shale formation. At least one property ofa portion of oil shale formation can usually be measured. The measuredproperty may include, but is not limited to, vitrinite reflectance,hydrogen content, atomic hydrogen to carbon ratio, oxygen content,atomic oxygen to carbon ratio, water content, thickness of the oil shaleformation, and/or the amount of stratification of the oil shaleformation into separate layers of rock and hydrocarbons.

[0622] In certain embodiments, a computer-implemented simulation mayinclude providing at least one measured property to a computer system.One or more sets of heat source spacings in the formation may also beprovided to the computer system. For example, a spacing between heatsources may be less than about 30 m. Alternatively, a spacing betweenheat sources may be less than about 15 m. The simulation may includedetermining properties of fluids produced from the portion as a functionof time for each set of heat source spacings. The produced fluids mayinclude formation fluids such as pyrolyzation fluids or synthesis gas.The determined properties may include, but are not limited to, APIgravity, carbon number distribution, olefin content, hydrogen content,carbon monoxide content, and/or carbon dioxide content. The determinedset of properties of the produced fluid may be compared to a set ofselected properties of a produced fluid. Sets of properties that matchthe set of selected properties may be determined. Furthermore, heatsource spacings may be matched to heat source spacings associated withdesired properties.

[0623] As shown in FIG. 16, unit cell 404 will often include a number ofheat sources 400 disposed within a formation around each production well402. An area of unit cell 404 may be determined by midlines 406 that maybe equidistant and perpendicular to a line connecting two productionwells 402. Vertices 408 of the unit cell may be at the intersection oftwo midlines 406 between production wells 402. Heat sources 400 may bedisposed in any arrangement within the area of unit cell 404. Forexample, heat sources 400 may be located within the formation such thata distance between each heat source varies by less than approximately10%, 20%, or 30%. In addition, heat sources 400 may be disposed suchthat an approximately equal space exists between each of the heatsources. Other arrangements of heat sources 400 within unit cell 404 maybe used. A ratio of heat sources 400 to production wells 402 may bedetermined by counting the number of heat sources 400 and productionwells 402 within unit cell 404 or over the total field.

[0624]FIG. 17 illustrates an embodiment of unit cell 404. Unit cell 404includes heat sources 400 and production well 402. Unit cell 404 mayhave six full heat sources 400 a and six partial heat sources 400 b.Full heat sources 400 a may be closer to production well 402 thanpartial heat sources 400 b. In addition, an entirety of each of fullheat sources 400 a may be located within unit cell 404. Partial heatsources 400 b may be partially disposed within unit cell 404. Only aportion of heat source 400 b disposed within unit cell 404 may provideheat to a portion of an oil shale formation disposed within unit cell404. A remaining portion of heat source 400 b disposed outside of unitcell 404 may provide heat to a remaining portion of the oil shaleformation outside of unit cell 404. To determine a number of heatsources within unit cell 404, partial heat source 400 b may be countedas one-half of full heat source 400 a. In other unit cell embodiments,fractions other than ½ (e.g., ⅓) may more accurately describe the amountof heat applied to a portion from a partial heat source based ongeometrical considerations.

[0625] The total number of heat sources 400 in unit cell 404 may includesix full heat sources 400 a that are each counted as one heat source,and six partial heat sources 400 b that are each counted as one-half ofa heat source. Therefore, a ratio of heat sources 400 to productionwells 402 in unit cell 404 may be determined as 9:1. A ratio of heatsources to production wells may be varied, however, depending on, forexample, the desired heating rate of the oil shale formation, theheating rate of the heat sources, the type of heat source, the type ofoil shale formation, the composition of oil shale formation, the desiredcomposition of the produced fluid, and/or the desired production rate.Providing more heat source wells per unit area will allow faster heatingof the selected portion and thus hasten the onset of production.However, adding more heat sources will generally cost more money ininstallation and equipment. An appropriate ratio of heat sources toproduction wells may include ratios greater than about 5:1. In someembodiments, an appropriate ratio of heat sources to production wellsmay be about 10:1, 20:1, 50:1, or greater. If larger ratios are used,then project costs tend to decrease since less wells and equipment areneeded.

[0626] A selected section is generally the volume of formation that iswithin a perimeter defined by the location of the outermost heat sources(assuming that the formation is viewed from above). For example, if fourheat sources were located in a single square pattern with an area ofabout 100 m² (with each source located at a corner of the square), andif the formation had an average thickness of approximately 5 m acrossthis area, then the selected section would be a volume of about 500 m³(i.e., the area multiplied by the average formation thickness across thearea). In many commercial applications, many heat sources (e.g.,hundreds or thousands) may be adjacent to each other to heat a selectedsection, and therefore only the outermost heat sources (i.e., edge heatsources) would define the perimeter of the selected section.

[0627]FIG. 18 illustrates a typical computational system 6250 that issuitable for implementing various embodiments of the system and methodfor in situ processing of a formation. Each computational system 6250typically includes components such as one or more central processingunits (CPU) 6252 with associated memory mediums, represented by floppydisks or compact discs (CDs) 6260. The memory mediums may store programinstructions for computer programs, wherein the program instructions areexecutable by CPU 6252. Computational system 6250 may further includeone or more display devices such as monitor 6254, one or morealphanumeric input devices such as keyboard 6256, and one or moredirectional input devices such as mouse 6258. Computational system 6250is operable to execute the computer programs to implement (e.g.,control, design, simulate, and/or operate) in situ processing offormation systems and methods.

[0628] Computational system 6250 preferably includes one or more memorymediums on which computer programs according to various embodiments maybe stored. The term “memory medium” may include an installation medium,e.g., CD-ROM or floppy disks 6260, a computational system memory such asDRAM, SRAM, EDO DRAM, SDRAM, DDR SDRAM, Rambus RAM, etc., or anon-volatile memory such as a magnetic media (e.g., a hard drive) oroptical storage. The memory medium may include other types of memory aswell, or combinations thereof. In addition, the memory medium may belocated in a first computer that is used to execute the programs.Alternatively, the memory medium may be located in a second computer, orother computers, connected to the first computer (e.g., over a network).In the latter case, the second computer provides the programinstructions to the first computer for execution. Also, computationalsystem 6250 may take various forms, including a personal computer,mainframe computational system, workstation, network appliance, Internetappliance, personal digital assistant (PDA), television system, or otherdevice. In general, the term “computational system” can be broadlydefined to encompass any device, or system of devices, having aprocessor that executes instructions from a memory medium.

[0629] The memory medium preferably stores a software program orprograms for event-triggered transaction processing. The softwareprogram(s) may be implemented in any of various ways, includingprocedure-based techniques, component-based techniques, and/orobject-oriented techniques, among others. For example, the softwareprogram may be implemented using ActiveX controls, C++ objects,JavaBeans, Microsoft Foundation Classes (MFC), or other technologies ormethodologies, as desired. A CPU, such as host CPU 6252, executing codeand data from the memory medium, includes a system/process for creatingand executing the software program or programs according to the methodsand/or block diagrams described below.

[0630] In one embodiment, the computer programs executable bycomputational system 6250 may be implemented in an object-orientedprogramming language. In an object-oriented programming language, dataand related methods can be grouped together or encapsulated to form anentity known as an object. All objects in an object-oriented programmingsystem belong to a class, which can be thought of as a category of likeobjects that describes the characteristics of those objects. Each objectis created as an instance of the class by a program. The objects maytherefore be said to have been instantiated from the class. The classsets out variables and methods for objects that belong to that class.The definition of the class does not itself create any objects. Theclass may define initial values for its variables, and it normallydefines the methods associated with the class (e.g., includes theprogram code which is executed when a method is invoked). The class maythereby provide all of the program code that will be used by objects inthe class, hence maximizing re-use of code that is shared by objects inthe class.

[0631] Turning now to FIG. 19, a block diagram of one embodiment ofcomputational system 6270 including processor 6293 coupled to a varietyof system components through bus bridge 6292 is shown. Other embodimentsare possible and contemplated. In the depicted system, main memory 6296is coupled to bus bridge 6292 through memory bus 6294, and graphicscontroller 6288 is coupled to bus bridge 6292 through AGP bus 6290.Finally, a plurality of PCI devices 6282 and 6284 are coupled to busbridge 6292 through PCI bus 6276. Secondary bus bridge 6274 may furtherbe provided to accommodate an electrical interface to one or more EISAor ISA devices 6280 through EISA/ISA bus 6278. Processor 6293 is coupledto bus bridge 6292 through CPU bus 6295 and to optional L2 cache 6297.

[0632] Bus bridge 6292 provides an interface between processor 6293,main memory 6296, graphics controller 6288, and devices attached to PCIbus 6276. When an operation is received from one of the devicesconnected to bus bridge 6292, bus bridge 6292 identifies the target ofthe operation (e.g., a particular device or, in the case of PCI bus6276, that the target is on PCI bus 6276). Bus bridge 6292 routes theoperation to the targeted device. Bus bridge 6292 generally translatesan operation from the protocol used by the source device or bus to theprotocol used by the target device or bus.

[0633] In addition to providing an interface to an ISA/EISA bus for PCIbus 6276, secondary bus bridge 6274 may further incorporate additionalfunctionality, as desired. An input/output controller (not shown),either external from or integrated with secondary bus bridge 6274, mayalso be included within computational system 6270 to provide operationalsupport for keyboard and mouse 6272 and for various serial and parallelports, as desired. An external cache unit (not shown) may further becoupled to CPU bus 6295 between processor 6293 and bus bridge 6292 inother embodiments. Alternatively, the external cache may be coupled tobus bridge 6292 and cache control logic for the external cache may beintegrated into bus bridge 6292. L2 cache 6297 is further shown in abackside configuration to processor 6293. It is noted that L2 cache 6297may be separate from processor 6293, integrated into a cartridge (e.g.,slot 1 or slot A) with processor 6293, or even integrated onto asemiconductor substrate with processor 6293.

[0634] Main memory 6296 is a memory in which application programs arestored and from which processor 6293 primarily executes. A suitable mainmemory 6296 comprises DRAM (Dynamic Random Access Memory). For example,a plurality of banks of SDRAM (Synchronous DRAM), DDR (Double Data Rate)SDRAM, or Rambus DRAM (RDRAM) may be suitable.

[0635] PCI devices 6282 and 6284 are illustrative of a variety ofperipheral devices such as, for example, network interface cards, videoaccelerators, audio cards, hard or floppy disk drives or drivecontrollers, SCSI (Small Computer Systems Interface) adapters, andtelephony cards. Similarly, ISA device 6280 is illustrative of varioustypes of peripheral devices, such as a modem, a sound card, and avariety of data acquisition cards such as GPIB or field bus interfacecards.

[0636] Graphics controller 6288 is provided to control the rendering oftext and images on display 6286. Graphics controller 6288 may embody atypical graphics accelerator generally known in the art to renderthree-dimensional data structures that can be effectively shifted intoand from main memory 6296. Graphics controller 6288 may therefore be amaster of AGP bus 6290 in that it can request and receive access to atarget interface within bus bridge 6292 to thereby obtain access to mainmemory 6296. A dedicated graphics bus accommodates rapid retrieval ofdata from main memory 6296. For certain operations, graphics controller6288 may generate PCI protocol transactions on AGP bus 6290. The AGPinterface of bus bridge 6292 may thus include functionality to supportboth AGP protocol transactions as well as PCI protocol target andinitiator transactions. Display 6286 is any electronic display uponwhich an image or text can be presented. A suitable display 6286includes a cathode ray tube (“CRT”), a liquid crystal display (“LCD”),etc.

[0637] It is noted that, while the AGP, PCI, and ISA or EISA buses havebeen used as examples in the above description, any bus architecturesmay be substituted as desired. It is further noted that computationalsystem 6270 may be a multiprocessing computational system includingadditional processors (e.g., processor 6291 shown as an optionalcomponent of computational system 6270). Processor 6291 may be similarto processor 6293. More particularly, processor 6291 may be an identicalcopy of processor 6293. Processor 6291 may be connected to bus bridge6292 via an independent bus (as shown in FIG. 19) or may share CPU bus6295 with processor 6293. Furthermore, processor 6291 may be coupled toan optional L2 cache 6298 similar to L2 cache 6297.

[0638]FIG. 20 illustrates a flow chart of a computer-implemented methodfor treating an oil shale formation based on a characteristic of theformation. At least one characteristic 6370 may be input intocomputational system 6250. Computational system 6250 may process atleast one characteristic 6370 using a software executable to determine aset of operating conditions 6372 for treating the formation with in situprocess 6310. The software executable may process equations relating toformation characteristics and/or the relationships between formationcharacteristics. At least one characteristic 6370 may include, but isnot limited to, an overburden thickness, depth of the formation,vitrinite reflectance, type of formation, permeability, density,porosity, moisture content, and other organic maturity indicators, oilsaturation, water saturation, volatile matter content, kerogencomposition, oil chemistry, ash content, net-to-gross ratio, carboncontent, hydrogen content, oxygen content, sulfur content, nitrogencontent, mineralology, soluble compound content, elemental composition,hydrogeology, water zones, gas zones, barren zones, mechanicalproperties, or top seal character. Computational system 6250 may be usedto control in situ process 6310 using determined set of operatingconditions 6372.

[0639]FIG. 21 illustrates a schematic of an embodiment used to controlan in situ conversion process (ICP) in formation 6600. Barrier well6602, monitor well 6604, production well 6606, and heater well 6608 maybe placed in formation 6600. Barrier well 6602 may be used to controlwater conditions within formation 6600. Monitoring well 6604 may be usedto monitor subsurface conditions in the formation, such as, but notlimited to, pressure, temperature, product quality, or fractureprogression. Production well 6606 may be used to produce formationfluids (e.g., oil, gas, and water) from the formation. Heater well 6608may be used to provide heat to the formation. Formation conditions suchas, but not limited to, pressure, temperature, fracture progression(monitored, for instance, by acoustical sensor data), and fluid quality(e.g., product quality or water quality) may be monitored through one ormore of wells 6602, 6604, 6606, and 6608.

[0640] Surface data such as pump status (e.g., pump on or off), fluidflow rate, surface pressure/temperature, and heater power may bemonitored by instruments placed at each well or certain wells.Similarly, subsurface data such as pressure, temperature, fluid quality,and acoustical sensor data may be monitored by instruments placed ateach well or certain wells. Surface data 6610 from barrier well 6602 mayinclude pump status, flow rate, and surface pressure/temperature.Surface data 6612 from production well 6606 may include pump status,flow rate, and surface pressure/temperature. Subsurface data 6614 frombarrier well 6602 may include pressure, temperature, water quality, andacoustical sensor data. Subsurface data 6616 from monitoring well 6604may include pressure, temperature, product quality, and acousticalsensor data. Subsurface data 6618 from production well 6606 may includepressure, temperature, product quality, and acoustical sensor data.Subsurface data 6620 from heater well 6608 may include pressure,temperature, and acoustical sensor data.

[0641] Surface data 6610 and 6612 and subsurface data 6614, 6616, 6618,and 6620 may be monitored as analog data 6621 from one or more measuringinstruments. Analog data 6621 may be converted to digital data 6623 inanalog-to-digital converter 6622. Digital data 6623 may be provided tocomputational system 6250. Alternatively, one or more measuringinstruments may provide digital data to computational system 6250.Computational system 6250 may include a distributed central processingunit (CPU). Computational system 6250 may process digital data 6623 tointerpret analog data 6621. Output from computational system 6250 may beprovided to remote display 6624, data storage 6626, display 6628, or toa surface facility 6630. Surface facility 6630 may include, for example,a hydrotreating plant, a liquid processing plant, or a gas processingplant. Computational system 6250 may provide digital output 6632 todigital-to-analog converter 6634. Digital-to-analog converter 6634 mayconverter digital output 6632 to analog output 6636.

[0642] Analog output 6636 may include instructions to control one ormore conditions of formation 6600. Analog output 6636 may includeinstructions to control the ICP within formation 6600. Analog output6636 may include instructions to adjust one or more parameters of theICP. The one or more parameters may include, but are not limited to,pressure, temperature, product composition, and product quality. Analogoutput 6636 may include instructions for control of pump status 6640 orflow rate 6642 at barrier well 6602. Analog output 6636 may includeinstructions for control of pump status 6644 or flow rate 6646 atproduction well 6606. Analog output 6636 may also include instructionsfor control of heater power 6648 at heater well 6608. Analog output 6636may include instructions to vary one or more conditions such as pumpstatus, flow rate, or heater power. Analog output 6636 may also includeinstructions to turn on and/or off pumps, heaters, or monitoringinstruments located at each well.

[0643] Remote input data 6638 may also be provided to computationalsystem 6250 to control conditions within formation 6600. Remote inputdata 6638 may include data used to adjust conditions of formation 6600.Remote input data 6638 may include data such as, but not limited to,electricity cost, gas or oil prices, pipeline tariffs, data fromsimulations, plant emissions, or refinery availability. Remote inputdata 6638 may be used by computational system 6250 to adjust digitaloutput 6632 to a desired value. In some embodiments, surface facilitydata 6650 may be provided to computational system 6250.

[0644] An in situ conversion process (ICP) may be monitored using afeedback control process. Conditions within a formation may be monitoredand used within the feedback control process. A formation being treatedusing an in situ conversion process may undergo changes in mechanicalproperties due to the conversion of solids and viscous liquids tovapors, fracture propagation (e.g., to overburden, underburden, watertables, etc.), increases in permeability or porosity and decreases indensity, moisture evaporation, and/or thermal instability of matrixminerals (leading to dehydration and decarbonation reactions and shiftsin stable mineral assemblages).

[0645] Remote monitoring techniques that will sense these changes inreservoir properties may include, but are not limited to, 4D (4dimension) time lapse seismic monitoring, 3D/3C (3 dimension/3component) seismic passive acoustic monitoring of fracturing, time lapse3D seismic passive acoustic monitoring of fracturing, electricalresistivity, thermal mapping, surface or downhole tilt meters, surveyingpermanent surface monuments, chemical sniffing or laser sensors forsurface gas abundance, and gravimetrics. More direct subsurface-basedmonitoring techniques may include high temperature downholeinstrumentation (such as thermocouples and other temperature sensingmechanisms, stress sensors, or instrumentation in the producer well todetect gas flows on a finely incremental basis).

[0646] In certain embodiments, a “base” seismic monitoring may beconducted, and then subsequent seismic results can be compared todetermine changes.

[0647] Simulation methods on a computer system may be used to model anin situ process for treating a formation. Simulations may determineand/or predict operating conditions (e.g., pressure, temperature, etc.),products that may be produced from the formation at given operatingconditions, and/or product characteristics (e.g., API gravity, aromaticto paraffin ratio, etc.) for the process. In certain embodiments, acomputer simulation may be used to model fluid mechanics (including masstransfer and heat transfer) and kinetics within the formation todetermine characteristics of products produced during heating of theformation. A formation may be modeled using commercially availablesimulation programs such as STARS, THERM, FLUENT, or CFX. In addition,combinations of simulation programs may be used to more accuratelydetermine or predict characteristics of the in situ process. Results ofthe simulations may be used to determine operating conditions within theformation prior to actual treatment of the formation. Results of thesimulations may also be used to adjust operating conditions duringtreatment of the formation based on a change in a property of theformation and/or a change in a desired property of a product producedfrom the formation.

[0648]FIG. 22 illustrates a flowchart of an embodiment of method 9470for modeling an in situ process for treating an oil shale formationusing a computer system. Method 9470 may include providing at least oneproperty 9472 of the formation to the computer system. Properties of theformation may include, but are not limited to, porosity, permeability,saturation, thermal conductivity, volumetric heat capacity,compressibility, composition, and number and types of phases in theformation. Properties may also include chemical components, chemicalreactions, and kinetic parameters. At least one operating condition 9474of the process may also be provided to the computer system. Forinstance, operating conditions may include, but are not limited to,pressure, temperature, heating rate, heat input rate, process time,weight percentage of gases, production characteristics (e.g., flowrates, locations, compositions), and peripheral water recovery orinjection. In addition, operating conditions may include characteristicsof the well pattern such as producer well location, producer wellorientation, ratio of producer wells to heater wells, heater wellspacing, type of heater well pattern, heater well orientation, anddistance between an overburden and horizontal heater wells.

[0649] Furthermore, a method may include assessing at least one processcharacteristic 9478 of the in situ process using simulation method 9476on the computer system. At least one process characteristic may beassessed as a function of time from at least one property of theformation and at least one operating condition. Process characteristicsmay include properties of a produced fluid such as API gravity, olefincontent, carbon number distribution, ethene to ethane ratio, atomiccarbon to hydrogen ratio, and ratio of non condensable hydrocarbons tocondensable hydrocarbons (gas/oil ratio). Process characteristics mayalso include a pressure and temperature in the formation, total massrecovery from the formation, and/or production rate of fluid producedfrom the formation.

[0650] In some embodiments, a simulation method may include a numericalsimulation method used/performed on the computer system. The numericalsimulation method may employ finite difference methods to solve fluidmechanics, heat transfer, and chemical reaction equations as a functionof time. A finite difference method may use a body-fitted grid systemwith unstructured grids to model a formation. An unstructured gridemploys a wide variety of shapes to model a formation geometry, incontrast to a structured grid. A body-fitted finite differencesimulation method may calculate fluid flow and heat transfer in aformation. Heat transfer mechanisms may include conduction, convection,and radiation. The body-fitted finite difference simulation method mayalso be used to treat chemical reactions in the formation. Simulationswith a finite difference simulation method may employ closed valuethermal conduction equations to calculate heat transfer and temperaturedistributions in the formation. A finite difference simulation methodmay determine values for heat injection rate data.

[0651] In an embodiment, a body-fitted finite difference simulationmethod may be well suited for simulating systems that include sharpinterfaces in physical properties or conditions. In general, abody-fitted finite difference simulation method may be more accurate, incertain circumstances, than space-fitted methods due to the use offiner, unstructured grids in body-fitted methods. For instance, it maybe advantageous to use a body-fitted finite difference simulation methodto calculate heat transfer in a heater well and in the region near orclose to a heater well. The temperature profile in and near a heaterwell may be relatively sharp. A region near a heater well may bereferred to as a “near wellbore region.” The size or radius of a nearwellbore region may depend on the type of formation. A general criteriafor determining or estimating the radius of a “near wellbore region” maybe a distance at which heat transfer by the mechanism of convectioncontributes significantly to overall heat transfer. Heat transfer in thenear wellbore region is typically limited to contributions fromconductive and/or radiative heat transfer. Convective heat transfertends to contribute significantly to overall heat transfer at locationswhere fluids flow within the formation (i.e., convective heat transferis significant where the flow of mass contributes to heat transfer).

[0652] In general, the radius of a near wellbore region in a formationdecreases with both increasing convection and increasing variation ofthermal properties with temperature in the formation

[0653] An oil shale formation may have a relatively large near wellboreregion due to the relatively small contribution of convection for heattransfer and a small variation in thermal properties with temperature.For example, an oil shale formation may have a near wellbore region witha radius between about 5 m and about 7 m. In other embodiments, theradius may be between about 7 m and about 10 m.

[0654] In a simulation of a heater well and near wellbore region, abody-fitted finite difference simulation method may calculate the heatinput rate that corresponds to a given temperature in a heater well. Themethod may also calculate the temperature distributions both inside thewellbore and at the near wellbore region.

[0655] CFX supplied by AEA Technologies in the United Kingdom is anexample of a commercially available body-fitted finite differencesimulation method. FLUENT is another commercially available body-fittedfinite difference simulation method from FLUENT, Inc. located inLebanon, N.H. FLUENT may simulate models of a formation that includeporous media and heater wells. The porous media models may include oneor more materials and/or phases with variable fractions. The materialsmay have user-specified temperature dependent thermal properties anddensities. The user may also specify the initial spatial distribution ofthe materials in a model. In one modeling scheme of a porous media, acombustion reaction may only involve a reaction between carbon andoxygen. In a model of hydrocarbon combustion, the volume fraction andporosity of the formation tend to decrease. In addition, a gas phase maybe modeled by one or more species in FLUENT, for example, nitrogen,oxygen, and carbon dioxide.

[0656] In an embodiment, the simulation method may include a numericalsimulation method on a computer system that uses a space-fitted finitedifference method with structured grids. The space-fitted finitedifference simulation method may be a reservoir simulation method. Areservoir simulation method may calculate fluid mechanics, massbalances, heat transfer, and/or kinetics in the formation. A reservoirsimulation method may be particularly useful for modeling multiphaseporous media in which convection (e.g., the flow of hot fluids) is arelatively important mechanism of heat transfer.

[0657] STARS is an example of a reservoir simulation method provided byComputer Modeling Group, Ltd. of Alberta, Canada. STARS is designed forsimulating steam flood, steam cycling, steam-with-additives, dry and wetcombustion, along with many types of chemical additive processes, usinga wide range of grid and porosity models in both field and laboratoryscales. STARS includes options such as thermal applications, steaminjection, fireflood, horizontal wells, dual porosity/permeability,directional permeability, and flexible grids. STARS allows for complextemperature dependent models of thermal and physical properties. STARSmay also simulate pressure dependent chemical reactions. STARS maysimulate a formation using a combination of structured space-fittedgrids and unstructured body-fitted grids. Additionally, THERM is anexample of a reservoir simulation method provided by Scientific SoftwareIntercomp.

[0658] In certain embodiments, a simulation method may use properties ofa formation. In general, the properties of a formation for a model of anin situ process depend on the type of formation. In a model of an oilshale formation, for example, a porosity value may be used to model anamount of kerogen and hydrated mineral matter in the formation. Thekerogen and hydrated mineral matter used in a model may be determined orapproximated by the amount of kerogen and hydrated mineral matternecessary to generate the oil, gas and water produced in laboratoryexperiments. The remainder of the volume of the oil shale may be modeledas inert mineral matter, which may be assumed to remain intact at allsimulated temperatures. During a simulation, hydrated mineral matterdecomposes to produce water and minerals. In addition, kerogen pyrolyzesduring the simulation to produce hydrocarbons and other compoundsresulting in a rise in fluid porosity. In some embodiments, the changein porosity during a simulation may be determined by monitoring theamount of solids that are treated/transformed, and fluids that aregenerated.

[0659] Some embodiments of a simulation method may require an initialpermeability of a formation and a relationship for the dependence ofpermeability on conditions of the formation. An initial permeability ofa formation may be determined from experimental measurements of a sample(e.g., a core sample) of a formation. In some embodiments, a ratio ofvertical permeability to horizontal permeability may be adjusted to takeinto consideration cleating in the formation.

[0660] In some embodiments, the porosity of a formation may be used tomodel the change in permeability of the formation during a simulation.For example, the permeability of oil shale often increases withtemperature due to the loss of solid matter from the decomposition ofmineral matter and the pyrolysis of kerogen. In one embodiment, thedependence of porosity on permeability may be described by an analyticalrelationship. For example, the effect of pyrolysis on permeability, K,may be governed by a Carman-Kozeny type formula shown in EQN. 2:

K(φ_(f))=K ₀(φ_(f)/φ_(f,0))^(CKpower)[(1−φ_(f,0))/(1−φ_(f)]²  (2)

[0661] where φ_(f) is the current fluid porosity, φ_(f,0) is the initialfluid porosity, K₀ is the permeability at initial fluid porosity, andCKpower is a user-defined exponent. The value of CKpower may be fittedby matching or approximating the pressure gradient in an experiment in aformation. The porosity-permeability relationship 9350 is plotted inFIG. 23 for a value of the initial porosity of 0.935 millidarcy andCKpower=0.95.

[0662] In certain embodiments, the thermal conductivity of a model of aformation may be expressed in terms of the thermal conductivities ofconstituent materials. For example, the thermal conductivity may beexpressed in terms of solid phase components and fluid phase components.The solid phase in oil shale formations may be composed of inert mineralmatter and organic solid matter. One or more fluid phases in theformations may include, for example, a water phase, an oil phase, and agas phase. In some embodiments, the dependence of the thermalconductivity on constituent materials in an oil shale formation may bemodeled according to EQN. 3:

k _(th)(T)=φ_(f)×(k _(th,w) ×S _(w) +k _(th,0) ×S ₀ +k _(th,g) ×S_(g))+(1−φ)×k _(th,r)(T)+(φ−φ_(f))×k _(th,s)  (3)

[0663] where φ is the porosity of the formation, φ_(f) is theinstantaneous fluid porosity, k_(th,i) is the thermal conductivity ofphase i=(w,o,g)=(water,oil,gas), S_(i) is the saturation of phasei=(w,o,g)=(water,oil,gas), k_(th,r)(T) is the thermal conductivity ofrock (inert mineral matter), and k_(th,s)(T) is the thermal conductivityof solid-phase components. The thermal conductivity, from EQN. 3, may bea function of temperature due to the temperature dependence of the solidphase components. The thermal conductivity also changes with temperaturedue to the change in composition of the fluid phase and porosity.

[0664] In some embodiments, a model may take into account the effect ofdifferent geological strata on properties of the formation. A propertyof a formation may be calculated for a given mineralogical composition.

[0665] In an embodiment, the volumetric heat capacity, ρ_(b)C_(p), mayalso be modeled as a direct function of temperature. However, thevolumetric heat capacity also depends on the composition of theformation material through the density, which is affected bytemperature.

[0666] In one embodiment, properties of the formation may include one ormore phases with one or more chemical components. For example, fluidphases may include water, oil, and gas. Solid phases may include mineralmatter and organic matter. Each of the fluid phases in an in situprocess may include a variety of chemical components such ashydrocarbons, H₂, CO₂, etc. The chemical components may be products ofone or more chemical reactions, such as pyrolysis reactions, that occurin the formation. Some embodiments of a model of an in situ process mayinclude modeling individual chemical components known to be present in aformation. However, inclusion of chemical components in a model of an insitu process may be limited by available experimental composition andkinetic data for the components. In addition, a simulation method mayalso place numerical and solution time limitations on the number ofcomponents that may be modeled.

[0667] In some embodiments, one or more chemical components may bemodeled as a single component called a pseudo-component. In certainembodiments, the oil phase may be modeled by two volatilepseudo-components, a light oil and a heavy oil. The oil and at leastsome of the gas phase components are generated by pyrolysis of organicmatter in the formation. The light oil and the heavy oil may be modeledas having an API gravity that is consistent with laboratory orexperimental field data. For example, the light oil may have an APIgravity of between about 20° and about 70°. The heavy oil may have anAPI gravity less than about 20°.

[0668] In some embodiments, hydrocarbon gases in a formation of one ormore carbon numbers may be modeled as a single pseudo-component. Inother embodiments, non-hydrocarbon gases and hydrocarbon gases may bemodeled as a single component. For example, hydrocarbon gases between acarbon number of one to a carbon number of five and nitrogen andhydrogen sulfide may be modeled as a single component. In someembodiments, the multiple components modeled as a single component haverelatively similar molecular weights. A molecular weight of thehydrocarbon gas pseudo-component may be set such that thepseudo-component is similar to a hydrocarbon gas generated in alaboratory pyrolysis experiment at a specified pressure.

[0669] In some embodiments of an in situ process, the composition of thegenerated hydrocarbon gas may vary with pressure. As pressure increases,the ratio of a higher molecular weight component to a lower molecularcomponent tends to increase. For example, as pressure increases, theratio of hydrocarbon gases with carbon numbers between about three andabout five to hydrocarbon gases with one and two carbon numbers tends toincrease. Consequently, the molecular weight of the pseudo-componentthat models a mixture of component gases may vary with pressure.

[0670] TABLE 1 lists components in a model of an in situ process in anoil shale formation according to an embodiment. TABLE 1 CHEMICALCOMPONENTS IN A MODEL OF AN OIL SHALE FORMATION. Component Phase MW H₂OAqueous 18.016 heavy oil Oil 317.96 light oil Oil 154.11 HCgas Gas26.895 H₂ Gas 2.016 CO₂ Gas 44.01 CO Gas 28.01 Hydramin Solid 15.153Kerogen Solid 15.153 Prechar Solid 12.72

[0671] The pseudo-component, HCgas, generated from pyrolysis in an oilshale formation, as shown in TABLE 1, may have critical properties veryclose to those of ethane. The HCgas pseudo-components may modelhydrocarbons between a carbon number of about one and a carbon number ofabout five. The molecular weight of the pseudo-component in TABLE 1generally reflects the composition of the hydrocarbon gas that wasgenerated in a laboratory experiment at a pressure of about 6.9 barsabsolute.

[0672] In some embodiments, the solid phase in a formation may bemodeled with one or more components. The components in a kerogenformation may include kerogen and a hydrated mineral phase (hydramin),as shown in TABLE 1. The hydrated mineral component may be included tomodel water and carbon dioxide generated in an oil shale formation attemperatures below a pyrolysis temperature of kerogen. The hydratedminerals, for example, may include illite and nahcolite.

[0673] Kerogen may be the source of most or all of the hydrocarbonfluids generated by the pyrolysis. Kerogen may also be the source ofsome of the water and carbon dioxide that is generated at temperaturesbelow a pyrolysis temperature.

[0674] In an embodiment, the solid phase model may also include one ormore intermediate components that are artifacts of the reactions thatmodel the pyrolysis. An oil shale formation may include at least oneintermediate component, prechar, as shown in TABLE 1. The precharsolid-phase components may model carbon residue in a formation that maycontain H₂ and low molecular weight hydrocarbons. In one embodiment, thenumber of intermediate components may be increased to improve the matchor agreement between simulation results and experimental results.

[0675] In one embodiment, a model of an in situ process may include oneor more chemical reactions. A number of chemical reactions are known tooccur in an in situ process for an oil shale formation. The chemicalreactions may belong to one of several categories of reactions. Thecategories may include, but not be limited to, generation ofpre-pyrolysis water and carbon dioxide, generation of hydrocarbons,coking and cracking of hydrocarbons, formation of synthesis gas, andcombustion and oxidation of coke.

[0676] In one embodiment, the rate of change of the concentration ofspecies X due to a chemical reaction, for example:

X→products  (I)

[0677] may be expressed in terms of a rate law:

d[X]/dt=−k[X] ^(n)  (II)

[0678] Species X in the chemical reaction undergoes chemicaltransformation to the products. [X] is the concentration of species X, tis the time, k is the reaction rate constant, and n is the order of thereaction. The reaction rate constant, k, may be defined by the Arrheniusequation:

k=A exp[−E _(a) /RT]  (III)

[0679] where A is the frequency factor, E_(a) is the activation energy,R is the universal gas constant, and T is the temperature. Kineticparameters, such as k, A, E_(a), and n, may be determined fromexperimental measurements. A simulation method may include one or morerate laws for assessing the change in concentration of species in an insitu process as a function of time. Experimentally determined kineticparameters for one or more chemical reactions may be used as input tothe simulation method.

[0680] In some embodiments, the number and categories of reactions in amodel of an in situ process may depend on the availability ofexperimental kinetic data and/or numerical limitations of a simulationmethod. Generally, chemical reactions and kinetic parameters for a modelmay be chosen such that simulation results match or approximatequantitative and qualitative experimental trends.

[0681] In some embodiments, reactions that model the generation ofpre-pyrolysis water and carbon dioxide account for the bound water,carbon dioxide, and carbon monoxide generated in a temperature rangebelow a pyrolysis temperature. For example, pre-pyrolysis water may begenerated from hydrated mineral matter. In one embodiment, thetemperature range may be between about 100° C. and about 270° C. Inother embodiments, the temperature range may be between about 80° C. andabout 300° C. Reactions in the temperature range below a pyrolysistemperature may account for between about 45% and about 60% of the totalwater generated and up to about 30% of the total carbon dioxide observedin laboratory experiments of pyrolysis.

[0682] In an embodiment, the pressure dependence of the chemicalreactions may be modeled. To account for the pressure dependence, asingle reaction with variable stoichiometric coefficients may be used tomodel the generation of pre-pyrolysis fluids. Alternatively, thepressure dependence may be modeled with two or more reactions withpressure dependent kinetic parameters such as frequency factors.

[0683] For example, experimental results indicate that the reaction thatgenerates pre-pyrolysis fluids from oil shale is a function of pressure.The amount of water generated generally decreases with pressure whilethe amount of carbon dioxide generated generally increases withpressure. In an embodiment, the generation of pre-pyrolysis fluids maybe modeled with two reactions to account for the pressure dependence.One reaction may be dominant at high pressures while the other may beprevalent at lower pressures. For example, a molar stoichiometry of tworeactions according to one embodiment may be written as follows:

1 mol hydramin→0.5884 mol H₂O+0.0962 mol CO₂+0.0114 mol CO  (4)

1 mol hydramin→0.8234 mol H₂O+0.0 mol CO₂+0.0114 mol CO  (5)

[0684] Experimentally determined kinetic parameters for Reactions (4)and (5) are shown in TABLE 2. TABLE 2 shows that pressure dependence ofReactions (4) and (5) is taken into account by the frequency factor. Thefrequency-factor increases with increasing pressure for Reaction (4),which results in an increase in the rate of product formation withpressure. The rate of product formation increases due to the increase inthe rate constant. In addition, the frequency-factor decreases withincreasing pressure for Reaction (5), which results in a decrease in therate of product formation with increasing pressure. Therefore, thevalues of the frequency-factor in TABLE 2 indicate that Reaction (4)dominates at high pressures while Reaction (5) dominates at lowpressures. In addition, the molar balances for Reactions (4) and (5)indicate that Reaction (4) generates less water and more carbon dioxidethan Reaction (5).

[0685] In one embodiment, a reaction enthalpy may be used by asimulation method such as STARS to assess the thermodynamic propertiesof a formation. In TABLES 2-5, the reaction enthalpy is a negativenumber if a chemical reaction is endothermic and positive if a chemicalreaction is exothermic. TABLE 2 KINETIC PARAMETERS OF PRE-PYROLYSISFLUID GENERATION REACTIONS IN AN OIL SHALE FORMATION. Pressure FrequencyActivation Reaction (bars Factor Energy Enthalpy Reaction absolute)[(day)⁻¹] (KJ/mole) Order (KJ/mole) 4 1.0432 1.197 × 10⁹  125,600 1 04.482 7.938 × 10¹⁰ 7.929 2.170 × 10¹¹ 11.376 4.353 × 10¹¹ 14.824 7.545 ×10¹¹ 18.271 1.197 × 10¹² 5 1.0432 1.197 × 10¹² 125,600 1 0 4.482 5.176 ×10¹¹ 7.929 2.037 × 10¹¹ 11.376 6.941 × 10¹⁰ 14.824 1.810 × 10¹⁰ 18.2711.197 × 10⁹ 

[0686] In other embodiments, the generation of hydrocarbons in apyrolysis temperature range in a formation may be modeled with one ormore reactions. One or more reactions may model the amount ofhydrocarbon fluids and carbon residue that are generated in a pyrolysistemperature range. Hydrocarbons generated may include light oil, heavyoil, and non-condensable gases. Pyrolysis reactions may also generatewater, H₂, and CO₂.

[0687] Experimental results indicate that the composition of productsgenerated in a pyrolysis temperature range may depend on operatingconditions such as pressure. For example, the production rate ofhydrocarbons generally decreases with pressure. In addition, the amountof produced hydrogen gas generally decreases substantially withpressure, the amount of carbon residue generally increases withpressure, and the amount of condensable hydrocarbons generally decreaseswith pressure. Furthermore, the amount of non-condensable hydrocarbonsgenerally increases with pressure such that the sum of condensablehydrocarbons and non-condensable hydrocarbons generally remainsapproximately constant with a change in pressure. In addition, the APIgravity of the generated hydrocarbons increases with pressure.

[0688] In an embodiment, the generation of hydrocarbons in a pyrolysistemperature range in an oil shale formation may be modeled with tworeactions. One of the reactions may be dominant at high pressures, theother prevailing at low pressures. For example, the molar stoichiometryof the two reactions according to one embodiment may be as follows:

1 mol kerogen→0.02691 mol H₂O+0.009588 mol heavy oil+0.01780 mol lightoil+0.04475 mol HCgas+0.01049 mol H₂+0.00541 mol CO₂+0.5827 molprechar  (6)

1 mol kerogen→0.02691 mol H₂O+0.009588 mol heavy oil+0.01780 mol lightoil+0.04475 mol HCgas+0.07930 mol H₂+0.00541 mol CO₂ +0.5718 molprechar  (7)

[0689] Experimentally determined kinetic parameters are shown in TABLE3. Reactions (6) and (7) model the pressure dependence of hydrogen andcarbon residue on pressure. However, the reactions do not take intoaccount the pressure dependence of hydrocarbon production. In oneembodiment, the pressure dependence of the production of hydrocarbonsmay be taken into account by a set of cracking/coking reactions.Alternatively, pressure dependence of hydrocarbon production may bemodeled by hydrocarbon generation reactions without cracking/cokingreactions. TABLE 3 KINETIC PARAMETERS OF PRE-PYROLYSIS GENERATIONREACTIONS IN AN OIL SHALE FORMATION. Pressure Frequency ActivationReaction (bars Factor Energy Enthalpy Reaction absolute) [(day)⁻¹](KJ/mole) Order (KJ/mole) 6 1.0432 1.000 × 10⁹  196398 1 0 4.482 2.620 ×10¹² 7.929 2.610 × 10¹² 11.376 1.975 × 10¹² 14.824 1.620 × 10¹² 18.2711.317 × 10¹² 7 1.0432 4.935 × 10¹² 196398 1 0 4.482 1.195 × 10¹² 7.9292.940 × 10¹¹ 11.376 7.250 × 10¹⁰ 14.824 1.840 × 10¹⁰ 18.271 1.100 × 10¹⁰

[0690] In one embodiment, one or more reactions may model the crackingand coking in a formation. Cracking reactions involve the reaction ofcondensable hydrocarbons (e.g., light oil and heavy oil) to form lightercompounds (e.g., light oil and non-condensable gases) and carbonresidue. The coking reactions model the polymerization and condensationof hydrocarbon molecules. Coking reactions lead to formation of char,lower molecular weight hydrocarbons, and hydrogen. Gaseous hydrocarbonsmay undergo coking reactions to form carbon residue and H₂. Coking andcracking may account for the deposition of coke in the vicinity ofheater wells where the temperature may be substantially greater than apyrolysis temperature. For example, the molar stoichiometry of thecracking and coking reactions in an oil shale formation according to oneembodiment may be as follows:

1 mol heavy oil (gas phase)→1.8530 mol light oil+0.045 mol HCgas+2.4515mol prechar  (8)

1 mol light oil (gas phase)→5.730 mol HCgas  (9)

1 mol heavy oil (liquid phase)→0.2063 mol light oil+2.365 molHCgas+17.497 mol prechar  (9)

1 mol light oil (liquid phase)→0.5730 mol HCgas+10.904 mol prechar  (11)

1 mol HCgas→2.8 mol H₂+1.6706 mol char  (12)

[0691] Kinetics parameters for Reactions 8 to 12 are listed in TABLE 4.The kinetics parameters of the cracking reactions were chosen to matchor approximate the oil and gas production observed in laboratoryexperiments. The kinetics parameter of the coking reaction was derivedfrom experimental data on pyrolysis reactions. TABLE 4 KINETICPARAMETERS OF CRACKING AND COKING REACTIONS IN AN OIL SHALE FORMATION.Pressure Frequency Activation Reaction (bars Factor Energy EnthalpyReaction absolute) [(day)⁻¹] (KJ/mole) Order (KJ/mole) 8 1.0432 6.250 ×10¹⁶ 206034 1 0 4.482 7.929 11.376 14.824 18.271 7.950 × 10¹⁶ 9 1.04329.850 × 10¹⁶ 266557 1 0 4.482 7.929 11.376 14.824 18.271 5.850 × 10¹⁶ 10— 2.647 × 10²⁰ 206034 1 0 11 — 3.820 × 10²⁰ 266557 1 0 12 — 7.660 × 10²⁰378494 1 0

[0692] In addition, reactions may model the generation of water at atemperature below or within a pyrolysis temperature range and thegeneration of hydrocarbons at a temperature in a pyrolysis temperaturerange in a coal formation. For example, according to one embodiment, thereactions may include:

1 mol coal→0.01894 mol H₂O+0.0004.91 mol HCgas+0.000047 mol H₂+0.0006.8mol CO₂+0.99883 mol coalbtm  (13)

1 mol coalbtm→0.02553 mol H₂O+0.00136 mol heavy oil+0.003174 mol lightoil+0.01618 mol HCgas+0.0032 mol H₂ +0.005599 mol CO ₂+0.0008.26 molCO+0.91306 mol prechar  (14)

1 mol prechar→0.02764 mol H₂O+0.05764 mol HCgas+0.02823 mol H ₂+0.0154mol CO₂+0.006.465 mol CO+0.90598 mol char  (15)

[0693] Reaction (13) models the generation of water in a temperaturerange below a pyrolysis temperature. Reaction (14) models the generationof hydrocarbons, such as oil and gas, generated in a pyrolysistemperature range. Reaction (15) models gas generated at temperaturesbetween about 370° C. and about 600° C.

[0694] In certain embodiments, the generation of synthesis gas in aformation may be modeled by one or more reactions. For example, themolar stoichiometry of four synthesis gas reactions may be according toone embodiment:

1 mol 0.9442 char+1.0 mol CO₂→2.0 mol CO  (16)

1.0 mol CO→0.5 mol CO₂+0.4721 mol char  (17)

0.94426 mol char+1.0 mol H₂O→1.0 mol H₂+1.0 mol CO  (18)

1.0 mol H₂+1.0 mol CO→0.94426 mol char+1.0 mol H₂O  (19)

[0695] The kinetic parameters of the four reactions are tabulated inTABLE 5. Kinetic parameters for Reactions 16-19 were based on literaturedata that were adjusted to fit the results of a cube laboratoryexperiment. Pressure dependence of reactions in the formation is nottaken in to account in TABLE 5. In one embodiment, pressure dependenceof the reactions in the formation may be modeled, for example, withpressure dependent frequency-factors. TABLE 5 KINETIC PARAMETERS FORSYNTHESIS GAS REACTIONS IN A FORMATION. Reaction Frequency FactorActivation Energy Enthalpy Reaction (day × bar)⁻¹ (KJ/mole) Order(KJ/mole) 16 2.47 × 10¹¹ 169970 1 −173033 17 201.6 148.6 1 86516 18 6.44× 10¹⁴ 237015 1 −135138 19 2.73 × 10⁷ 103191 1 135138

[0696] In one embodiment, a combustion and oxidation reaction of coke tocarbon dioxide may be modeled in a formation. For example, the molarstoichiometry of a reaction according to one embodiment may be:

0.9442 mol char+1.0 mol O₂→1.0 mol CO₂  (20)

[0697] Experimentally derived kinetic parameters include a frequencyfactor of 1.0×10⁴ (day)⁻¹, an activation energy of 58,614 KJ/mole, anorder of 1, and a reaction enthalpy of 427,977 KJ/mole.

[0698] In an embodiment, a method of modeling an in situ process oftreating an oil shale formation using a computer system may includesimulating a heat input rate to the formation from two or more heatsources. FIG. 24 illustrates method 9360 for simulating heat transfer ina formation. Simulation method 9361 may simulate heat input rate 9368from two or more heat sources in the formation. For example, thesimulation method may be a body-fitted finite difference simulationmethod. The heat may be allowed to transfer from the heat sources to aselected section of the formation. In an embodiment, the superpositionof heat from the two or more heat sources may pyrolyze at least somehydrocarbons within the selected section of the formation. In oneembodiment, two or more heat sources may be simulated with a model ofheat sources with symmetry boundary conditions.

[0699] In some embodiments, the method may further include providing atleast one desired parameter 9366 of the in situ process to the computersystem. For example, the desired parameter may be a desired temperaturein the formation. In particular, the desired parameter may be a maximumtemperature at specific locations in the formation. In addition, thedesired parameter may be a desired heating rate or a desired productcomposition. Desired parameters may also include other parameters suchas a desired pressure, process time, production rate, time to obtain agiven production rate, and product composition. Process characteristics9362 determined by simulation method 9361 may be compared 9364 to atleast one desired parameter 9366. The method may further includecontrolling 9363 the heat input rate from the heat sources (or someother process parameter) to achieve at least one desired parameter.Consequently, the heat input rate from the two or more heat sourcesduring a simulation may be time dependent.

[0700] In an embodiment, heat injection into a formation may beinitiated by imposing a constant flux per unit area at the interfacebetween a heater and the formation. When a point in the formation, suchas the interface, reaches a specified maximum temperature, the heat fluxmay be varied to maintain the maximum temperature. The specified maximumtemperature may correspond to the maximum temperature allowed for aheater well casing (e.g., a maximum operating temperature for themetallurgy in the heater well). In one embodiment, the maximumtemperature may be between about 600° C. and about 700° C. In otherembodiments, the maximum temperature may be between about 700° C. andabout 800° C. In some embodiments, the maximum temperature may begreater than about 800° C.

[0701]FIG. 25 illustrates a model for simulating a heat transfer rate ina formation. Model 9370 represents an aerial view of {fraction (1/12)}of a seven spot heater pattern in a formation. The pattern is composedof body-fitted grid elements 9371. The model includes horizontal heater9372 and producer 9374. A pattern of heaters in a formation is modeledby imposing symmetry boundary conditions. The elements near the heatersand in the region near the heaters are substantially smaller than otherportions of the formation to more effectively model a steep temperatureprofile.

[0702] In one embodiment, an in situ process may be modeled with morethan one simulation methods. FIG. 26 illustrates a flowchart of anembodiment of method 8630 for modeling an in situ process for treatingan oil shale formation using a computer system. At least one heat inputproperty 8632 may be provided to the computer system. The computersystem may include first simulation method 8634. At least one heat inputproperty 8632 may include a heat transfer property of the formation. Forexample, the heat transfer property of the formation may include heatcapacities or thermal conductivities of one or more components in theformation. In certain embodiments, at least one heat input property 8632includes an initial heat input property of the formation. Initial heatinput properties may also include, but are not limited to, volumetricheat capacity, thermal conductivity, porosity, permeability, saturation,compressibility, composition, and the number and types of phases.Properties may also include chemical components, chemical reactions, andkinetic parameters.

[0703] In certain embodiments, first simulation method 8634 may simulateheating of the formation. For example, the first simulation method maysimulate heating the wellbore and the near wellbore region. Simulationof heating of the formation may assess (i.e., estimate, calculate, ordetermine) heat injection rate data 8636 for the formation. In oneembodiment, heat injection rate data may be assessed to achieve at leastone desired parameter of the formation, such as a desired temperature orcomposition of fluids produced from the formation. First simulationmethod 8634 may use at least one heat input property 8632 to assess heatinjection rate data 8636 for the formation. First simulation method 8634may be a numerical simulation method. The numerical simulation may be abody-fitted finite difference simulation method. In certain embodiments,first simulation method 8634 may use at least one heat input property8632, which is an initial heat input property. First simulation method8634 may use the initial heat input property to assess heat inputproperties at later times during treatment (e.g., heating) of theformation.

[0704] Heat injection rate data 8636 may be used as input into secondsimulation method 8640. In some embodiments, heat injection rate data8636 may be modified or altered for input into second simulation method8640. For example, heat injection rate data 8636 may be modified as aboundary condition for second simulation method 8640. At least oneproperty 8638 of the formation may also be input for use by secondsimulation method 8640. Heat injection rate data 8636 may include atemperature profile in the formation at any time during heating of theformation. Heat injection rate data 8636 may also include heat flux datafor the formation. Heat injection rate data 8636 may also includeproperties of the formation.

[0705] Second simulation method 8640 may be a numerical simulationand/or a reservoir simulation method. In certain embodiments, secondsimulation method 8640 may be a space-fitted finite differencesimulation (e.g., STARS). Second simulation method 8640 may includesimulations of fluid mechanics, mass balances, and/or kinetics withinthe formation. The method may further include providing at least oneproperty 8638 of the formation to the computer system. At least oneproperty 8638 may include chemical components, reactions, and kineticparameters for the reactions that occur within the formation. At leastone property 8638 may also include other properties of the formationsuch as, but not limited to, permeability, porosities, and/or a locationand orientation of heat sources, injection wells, or production wells.

[0706] Second simulation method 8640 may assess at least one processcharacteristic 8642 as a function of time based on heat injection ratedata 8636 and at least one property 8638. In some embodiments, secondsimulation method 8640 may assess an approximate solution for at leastone process characteristic 8642. The approximate solution may be acalculated estimation of at least one process characteristic 8642 basedon the heat injection rate data and at least one property. Theapproximate solution may be assessed using a numerical method in secondsimulation method 8640. At least one process characteristic 8642 mayinclude one or more parameters produced by treating an oil shaleformation in situ. For example, at least one process characteristic 8642may include, but is not limited to, a production rate of one or moreproduced fluids, an API gravity of a produced fluid, a weight percentageof a produced component, a total mass recovery from the formation, andoperating conditions in the formation such as pressure or temperature.

[0707] In some embodiments, first simulation method 8634 and secondsimulation method 8640 may be used to predict process characteristicsusing parameters based on laboratory data. For example, experimentallybased parameters may include chemical components, chemical reactions,kinetic parameters, and one or more formation properties. Thesimulations may further be used to assess operating conditions that canbe used to produce desired properties in fluids produced from theformation. In additional embodiments, the simulations may be used topredict changes in process characteristics based on changes in operatingconditions and/or formation properties.

[0708] In certain embodiments, one or more of the heat input propertiesmay be initial values of the heat input properties. Similarly, one ormore of the properties of the formation may be initial values of theproperties. The heat input properties and the reservoir properties maychange during a simulation of the formation using the first and secondsimulation methods. For example, the chemical composition, porosity,permeability, volumetric heat capacity, thermal conductivity, and/orsaturation may change with time. Consequently, the heat input rateassessed by the first simulation method may not be adequate input forthe second simulation method to achieve a desired parameter of theprocess. In some embodiments, the method may further include assessingmodified heat injection rate data at a specified time of the secondsimulation. At least one heat input property 8641 of the formationassessed at the specified time of the second simulation method may beused as input by first simulation method 8634 to calculate the modifiedheat input data. Alternatively, the heat input rate may be controlled toachieve a desired parameter during a simulation of the formation usingthe second simulation method.

[0709] In some embodiments, one or more model parameters for input intoa simulation method may be based on laboratory or field test data of anin situ process for treating an oil shale formation. FIG. 27 illustratesa flow chart of an embodiment of method 9390 for calibrating modelparameters to match or approximate laboratory or field data for an insitu process. The method may include providing one or more modelparameters 9392 for the in situ process. The model parameters mayinclude properties of the formation. In addition, the model parametersmay also include relationships for the dependence of properties on thechanges in conditions, such as temperature and pressure, in theformation. For example, model parameters may include a relationship forthe dependence of porosity on pressure in the formation. Modelparameters may also include an expression for the dependence ofpermeability on porosity. Model parameters may include an expression forthe dependence of thermal conductivity on composition of the formation.In addition, model parameters may include chemical components, thenumber and types of reactions in the formation, and kinetic parameters.Kinetic parameters may include the order of a reaction, activationenergy, reaction enthalpy, and frequency factor.

[0710] In some embodiments, the method may include assessing one or moresimulated process characteristics 9396 based on the one or more modelparameters. Simulated process characteristics 9396 may be assessed usingsimulation method 9394. Simulation method 9394 may be a body-fittedfinite difference simulation method. Alternatively, simulation method9394 may be a reservoir simulation method.

[0711] In an embodiment, simulated process characteristics 9396 may becompared 9398 to real process characteristics 9400. Real processcharacteristics may be process characteristics obtained from laboratoryor field tests of an in situ process. Comparing process characteristicsmay include comparing the simulated process characteristics with thereal process characteristics as a function of time. Differences betweena simulated process characteristic and a real process characteristic maybe associated with one or more model parameters. For example, a higherratio of gas to oil of produced fluids from a real in situ process maybe due to a lack of pressure dependence of kinetic parameters. Themethod may further include modifying 9399 the one or more modelparameters such that at least one simulated process characteristicmatches or approximates at least one real process characteristic. One ormore model parameters may be modified to account for a differencebetween a simulated process characteristic and a real processcharacteristic. For example, an additional chemical reaction may beadded to account for pressure dependence or a discrepancy of an amountof a particular component in produced fluids.

[0712] Some embodiments may include assessing one or more modifiedsimulated process characteristics from simulation method 9394 based onmodified model parameters 9397. Modified model parameters may includeone or both of model parameters 9392 that have been modified and thathave not been modified. In an embodiment, the simulation method may usemodified model parameters 9397 to assess at least one operatingcondition of the in situ process to achieve at least one desiredparameter.

[0713] Method 9390 may be used to calibrate model parameters forgeneration reactions of pre-pyrolysis fluids and generation ofhydrocarbons from pyrolysis. For example, field test results may show alarger amount of H₂ produced from the formation than the simulationresults. The discrepancy may be due to the generation of synthesis gasin the formation in the field test. Synthesis gas may be generated fromwater in the formation, particularly near heater wells. The temperaturesnear heater wells may approach a synthesis gas generating temperaturerange even when the majority of the formation is below synthesis gasgenerating temperatures. Therefore, the model parameters for thesimulation method may be modified to include some synthesis gasreactions.

[0714] In addition, model parameters may be calibrated to account forthe pressure dependence of the production of low molecular weighthydrocarbons in a formation. The pressure dependence may arise in bothlaboratory and field scale experiments. As pressure increases, fluidstend to remain in a laboratory vessel or a formation for longer periodsof time. The fluids tend to undergo increased cracking and/or cokingwith increased residence time in the laboratory vessel or the formation.As a result, larger amounts of lower molecular weight hydrocarbons maybe generated. Increased cracking of fluids may be more pronounced in afield scale experiment (as compared to a lab experiment, or as comparedto calculated cracking) due to longer residence times since fluids maybe required to pass through significant distances (e.g., tens of meters)of formation before being produced from a formation.

[0715] Simulations may be used to calibrate kinetics parameters thataccount for the pressure dependence. For example, pressure dependencemay be accounted for by introducing cracking and coking reactions into asimulation. The reactions may include pressure dependent kineticparameters to account for the pressure dependence. Kinetics parametersmay be chosen to match or approximate hydrocarbon production reactionsparameters from experiments.

[0716] In certain embodiments, a simulation method based on a set ofmodel parameters may be used to design an in situ process. A field testof an in situ process based on the design may be used to calibrate themodel parameters. FIG. 28 illustrates a flowchart of an embodiment ofmethod 9405 for calibrating model parameters. Method 9405 may includeassessing at least one operating condition 9414 of the in situ processusing simulation method 9410 based on one or more model parameters.Operating conditions may include pressure, temperature, heating rate,heat input rate, process time, weight percentage of gases, peripheralwater recovery or injection. Operating conditions may also includecharacteristics of the well pattern such as producer well location,producer well orientation, ratio of producer wells to heater wells,heater well spacing, type of heater well pattern, heater wellorientation, and distance between an overburden and horizontal heaterwells. In one embodiment, at least one operating condition may beassessed such that the in situ process achieves at least one desiredparameter.

[0717] In some embodiments, at least one operating condition 9414 may beused in real in situ process 9418. In an embodiment, the real in situprocess may be a field test, or a field operation, operating with atleast one operating condition. The real in situ process may have one ormore real process characteristics 9420. Simulation method 9410 mayassess one or more simulated process characteristics 9412. In anembodiment, simulated process characteristics 9412 may be compared 9416to real process characteristics 9420. The one or more model parametersmay be modified such that at least one simulated process characteristic9412 from a simulation of the in situ process matches or approximates atleast one real process characteristic 9420 from the in situ process. Thein situ process may then be based on at least one operating condition.The method may further include assessing one or more modified simulatedprocess characteristics based on the modified model parameters 9417. Insome embodiments, simulation method 9410 may be used to control the insitu process such that the in situ process has at least one desiredparameter.

[0718] In one embodiment, a first simulation method may be moreeffective than a second simulation method in assessing processcharacteristics under a first set of conditions. Alternatively, thesecond simulation method may be more effective in assessing processcharacteristics under a second set of conditions. A first simulationmethod may include a body-fitted finite difference simulation method. Afirst set of conditions may include, for example, a relatively sharpinterface in an in situ process. In an embodiment, a first simulationmethod may use a finer grid than a second simulation method. Thus, thefirst simulation method may be more effective in modeling a sharpinterface. A sharp interface refers to a relatively large change in oneor more process characteristics in a relatively small region in theformation. A sharp interface may include a relatively steep temperaturegradient that may exist in a near wellbore region of a heater well. Arelatively steep gradient in pressure and composition, due to pyrolysis,may also exist in the near wellbore region. A sharp interface may alsobe present at a combustion or reaction front as it propagates through aformation. A steep gradient in temperature, pressure, and compositionmay be present at a reaction front.

[0719] In certain embodiments, a second simulation method may include aspace-fitted finite difference simulation method such as a reservoirsimulation method. A second set of conditions may include conditions inwhich heat transfer by convection is significant. In addition, a secondset of conditions may also include condensation of fluids in aformation.

[0720] In some embodiments, model parameters for the second simulationmethod may be calibrated such that the second simulation methodeffectively assesses process characteristics under both the first setand the second set of conditions. FIG. 29 illustrates a flow chart of anembodiment of method 9430 for calibrating model parameters for a secondsimulation method using a first simulation method. Method 9430 mayinclude providing one or more model parameters 9431 to a computersystem. One or more first process characteristics 9434 based on one ormore model parameters 9431 may be assessed using first simulation method9432 in memory on the computer system. First simulation method 9432 maybe a body-fitted finite difference simulation method. The modelparameters may include relationships for the dependence of propertiessuch as porosity, permeability, thermal conductivity, and heat capacityon the changes in conditions (e.g., temperature and pressure) in theformation. In addition, model parameters may include chemicalcomponents, the number and types of reactions in the formation, andkinetic parameters. Kinetic parameters may include the order of areaction, activation energy, reaction enthalpy, and frequency factor.Process characteristics may include, but are not limited to, atemperature profile, pressure, composition of produced fluids, and avelocity of a reaction or combustion front.

[0721] In certain embodiments, one or more second processcharacteristics 9440 based on one or more model parameters 9431 may beassessed using second simulation method 9438. Second simulation method9438 may be a space-fitted finite difference simulation method, such asa reservoir simulation method. One or more first process characteristics9434 may be compared 9436 to one or more second process characteristics9440. The method may further include modifying one or more modelparameters 9431 such that at least one first process characteristic 9434matches or approximates at least one second process characteristic 9440.For example, the order or the activation energy of the one or morechemical reactions may be modified to account for differences betweenthe first and second process characteristics. In addition, a singlereaction may be expressed as two or more reactions. In some embodiments,one or more third process characteristics based on the one or moremodified model parameters 9442 may be assessed using the secondsimulation method.

[0722] In one embodiment, simulations of an in situ process for treatingan oil shale formation may be used to design and/or control a real insitu process. Design and/or control of an in situ process may includeassessing at least one operating condition that achieves a desiredparameter of the in situ process. FIG. 30 illustrates a flow chart of anembodiment of method 9450 for the design and/or control of an in situprocess. The method may include providing to the computer system one ormore values of at least one operating condition 9452 of the in situprocess for use as input to simulation method 9454. The simulationmethod may be a space-fitted finite difference simulation method such asa reservoir simulation method or it may be a body-fitted simulationmethod such as FLUENT. At least one operating condition may include, butis not limited to, pressure, temperature, heating rate, heat input rate,process time, weight percentage of gases, peripheral water recovery orinjection, production rate, and time to reach a given production rate.In addition, operating conditions may include characteristics of thewell pattern such as producer well location, producer well orientation,ratio of producer wells to heater wells, heater well spacing, type ofheater well pattern, heater well orientation, and distance between anoverburden and horizontal heater wells.

[0723] In one embodiment, the method may include assessing one or morevalues of at least one process characteristic 9456 corresponding to oneor more values of at least one operating condition 9452 from one or moresimulations using simulation method 9454. In certain embodiments, avalue of at least one process characteristic may include the processcharacteristic as a function of time. A desired value of at least oneprocess characteristic 9460 for the in situ process may also be providedto the computer system. An embodiment of the method may further includeassessing 9458 desired value of at least one operating condition 9462 toachieve desired value of at least one process characteristic 9460.Desired value of at least one operating condition 9462 may be assessedfrom the values of at least one process characteristic 9456 and valuesof at least one operating condition 9452. For example, desired value9462 may be obtained by interpolation of values 9456 and values 9452. Insome embodiments, a value of at least one process characteristic may beassessed from the desired value of at least one operating condition 9462using simulation method 9454. In some embodiments, an operatingcondition to achieve a desired parameter may be assessed by comparing aprocess characteristic as a function of time for different operatingconditions. In an embodiment, the method may include operating the insitu system using the desired value of at least one additional operatingcondition.

[0724] In an alternate embodiment, a desired value of at least oneoperating condition to achieve the desired value of at least one processcharacteristic may be assessed by using a relationship between at leastone process characteristic and at least one operating condition of thein situ process. The relationship may be assessed from a simulationmethod. The relationship may be stored on a database accessible by thecomputer system. The relationship may include one or more values of atleast one process characteristic and corresponding values of at leastone operating condition. Alternatively, the relationship may be ananalytical function.

[0725] In an embodiment, a desired process characteristic may be aselected composition of fluids produced from a formation. A selectedcomposition may correspond to a ratio of non-condensable hydrocarbons tocondensable hydrocarbons. In certain embodiments, increasing thepressure in the formation may increase the ratio of non-condensablehydrocarbons to condensable hydrocarbons of produced fluids. Thepressure in the formation may be controlled by increasing the pressureat a production well in an in situ process. In an alternate embodiment,another operating condition may be controlled simultaneously (e.g., theheat input rate).

[0726] In an embodiment, the pressure corresponding to the selectedcomposition may be assessed from two or more simulations at two or morepressures. In one embodiment, at least one of the pressures of thesimulations may be estimated from EQN. 21: $\begin{matrix}{p = \exp^{\lbrack{\frac{A}{T} + B}\rbrack}} & (21)\end{matrix}$

[0727] where p is measured in psia (pounds per square inch absolute), Tis measured in Kelvin, and A and B are parameters dependent on the valueof the desired process characteristic for a given type of formation.Values of A and B may be assessed from experimental data for a processcharacteristic in a given formation and may be used as input to EQN. 21.The pressure corresponding to the desired value of the processcharacteristic may then be estimated for use as input into a simulation.

[0728] The two or more simulations may provide a relationship betweenpressure and the composition of produced fluids. The pressurecorresponding to the desired composition may be interpolated from therelationship. A simulation at the interpolated pressure may be performedto assess a composition and one or more additional processcharacteristics. The accuracy of the interpolated pressure may beassessed by comparing the selected composition with the composition fromthe simulation. The pressure at the production well may be set to theinterpolated pressure to obtain produced fluids with the selectedcomposition.

[0729] In certain embodiments, the pressure of a formation may bereadily controlled at certain stages of an in situ process. At somestages of the in situ process, however, pressure control may berelatively difficult. For example, during a relatively short period oftime after heating has begun the permeability of the formation may berelatively low. At such early stages, the heat transfer front at whichpyrolysis occurs may be at a relatively large distance from a producerwell (i.e., the point at which pressure may be controlled). Therefore,there may be a significant pressure drop between the producer well andthe heat transfer front. Consequently, adjusting the pressure at aproducer well may have a relatively small influence on the pressure atwhich pyrolysis occurs at early stages of the in situ process. At laterstages of the in situ process when permeability has developed relativelyuniformly throughout the formation, the pressure of the producer wellcorresponds to the pressure in the formation. Therefore, the pressure atthe producer well may be used to control the pressure at which pyrolysisoccurs.

[0730] In some embodiments, a similar procedure may be followed toassess heater well pattern and producer well pattern characteristicsthat correspond to a desired process characteristic. For example, arelationship between the spacing of the heater wells and composition ofproduced fluids may be obtained from two or more simulations withdifferent heater well spacings.

[0731] In one embodiment, a simulation method on a computer system maybe used in a method for modeling one or more stages of a process fortreating an oil shale formation in situ. The simulation method may be,for example, a reservoir simulation method. The simulation method maysimulate heating of the formation, fluid flow, mass transfer, heattransfer, and chemical reactions in one or more of the stages of theprocess. In some embodiments, the simulation method may also simulateremoval of contaminants from the formation, recovery of heat from theformation, and injection of fluids into the formation.

[0732] Method 9588 of modeling the one or more stages of a treatmentprocess is depicted in a flow chart in FIG. 31. The one or more stagesmay include heating stage 9574, pyrolyzation stage 9576, synthesis gasgeneration stage 9579, remediation stage 9582, and/or shut-in stage9585. The method may include providing at least one property 9572 of theformation to the computer system. In addition, operating conditions9573, 9577, 9580, 9583, and/or 9586 for one or more of the stages of thein situ process may be provided to the computer system. Operatingconditions may include, but not be limited to, pressure, temperature,heating rates, etc. In addition, operating conditions of a remediationstage may include a flow rate of ground water and injected water intothe formation, size of treatment area, and type of drive fluid.

[0733] In certain embodiments, the method may include assessing processcharacteristics 9575, 9578, 9581, 9584, and/or 9587 of the one or morestages using the simulation method. Process characteristics may includeproperties of a produced fluid such as API gravity and gas/oil ratio.Process characteristics may also include a pressure and temperature inthe formation, total mass recovery from the formation, and productionrate of fluid produced from the formation. In addition, a processcharacteristic of the remediation stage may include the type andconcentration of contaminants remaining in the formation.

[0734] In one embodiment, a simulation method may be used to assessoperating conditions of at least one of the stages of an in situ processthat results in desired process characteristics. FIG. 32 illustrates aflow chart of an embodiment of method 9701 for designing and controllingheating stage 9706, pyrolyzation stage 9708, synthesis gas generatingstage 9714, remediation stage 9720, and/or shut-in stage 9726 of an insitu process with a simulation method on a computer system. The methodmay include providing sets of operating conditions 9702, 9712, 9718,9724, and/or 9730 for at least one of the stages of the in situ process.In addition, desired process characteristics 9704, 9713, 9719, 9725,and/or 9731 for at least one of the stages of the in situ process mayalso be provided. The method may further include assessing at least oneadditional operating condition 9707, 9710, 9716, 9722, and/or 9728 forat least one of the stages that achieves the desired processcharacteristics of one or more stages.

[0735] In an embodiment, in situ treatment of an oil shale formation maysubstantially change physical and mechanical properties of theformation. The physical and mechanical properties may be affected bychemical properties of a formation, operating conditions, and processcharacteristics.

[0736] Changes in physical and mechanical properties due to treatment ofa formation may result in deformation of the formation. Deformationcharacteristics may include, but are not limited to, subsidence,compaction, heave, and shear deformation. Subsidence is a verticaldecrease in the surface of a formation over a treated portion of aformation. Heave is a vertical increase at the surface above a treatedportion of a formation. Surface displacement may result from severalconcurrent subsurface effects, such as the thermal expansion of layersof the formation, the compaction of the richest and weakest layers, andthe constraining force exerted by cooler rock that surrounds the treatedportion of the formation. In general, in the initial stages of heating aformation, the surface above the treated portion may show a heave due tothermal expansion of incompletely pyrolyzed formation material in thetreated portion of the formation. As a significant portion of formationbecomes pyrolyzed, the formation is weakened and pore pressure in thetreated portion declines. The pore pressure is the pressure of theliquid and gas that exists in the pores of a formation. The porepressure may be influenced by the thermal expansion of the organicmatter in the formation and the withdrawal of fluids from the formation.The decrease in the pore pressure tends to increase the effective stressin the treated portion. Since the pore pressure affects the effectivestress on the treated portion of a formation, pore pressure influencesthe extent of subsurface compaction in the formation. Compaction,another deformation characteristic, is a vertical decrease of asubsurface portion above or in the treated portion of the formation. Inaddition, shear deformation of layers both above and in the treatedportion of the formation may also occur. In some embodiments,deformation may adversely affect the in situ treatment process. Forexample, deformation may seriously damage surface facilities andwellbores.

[0737] In certain embodiments, an in situ treatment process may bedesigned and controlled such that the adverse influence of deformationis minimized or substantially eliminated. Computer simulation methodsmay be useful for design and control of an in situ process sincesimulation methods may predict deformation characteristics. For example,simulation methods may predict subsidence, compaction, heave, and sheardeformation in a formation from a model of an in situ process. Themodels may include physical, mechanical, and chemical properties of aformation. Simulation methods may be used to study the influence ofproperties of a formation, operating conditions, and processcharacteristics on deformation characteristics of the formation.

[0738]FIG. 33 illustrates model 9518 of a formation that may be used insimulations of deformation characteristics according to one embodiment.The formation model is a vertical cross-section that may include treatedportions 9524 with thickness 9532 and width or radius 9528. Treatedportion 9524 may include several layers or regions that vary in mineralcomposition and richness of organic matter. For example, in a model ofan oil shale formation, treated portion 9524 may include layers of leankerogenous chalk, rich kerogenous chalk, and silicified kerogenouschalk. In one embodiment, treated portion 9524 may be a dipping layerthat is at an angle to the surface of the formation. The model may alsoinclude untreated portions such as overburden 9521 and base rock 9526.Overburden 9521 may have thickness 9530. Overburden 9521 may alsoinclude one or more portions, for example, portion 9520 and portion 9522that differ in composition. For example, portion 9522 may have acomposition similar to treated portion 9524 prior to treatment. Portion9520 may be composed of organic material, soil, rock, etc. Base rock9526 may include barren rock with at least some organic material.

[0739] In some embodiments, an in situ process may be designed such thatit includes an untreated portion or strip between treated portions ofthe formation. FIG. 34 illustrates a schematic of a strip developmentaccording to one embodiment. The formation includes treated portion 9523and treated portion 9525 with thicknesses 9531 and widths 9533(thicknesses 9531 and widths 9533 may vary between portion 9523 andportion 9525). Untreated portion 9527 with width 9529 separates treatedportion 9523 from treated portion 9525. In some embodiments, width 9529is substantially less than widths 9533 since only smaller sections needto remain untreated to provide structural support. In some embodiments,the use of an untreated portion may decrease the amount of subsidence,heave, compaction, or shear deformation at and above the treatedportions of the formation.

[0740] In an embodiment, an in situ treatment process may be representedby a three-dimensional model. FIG. 35 depicts a schematic illustrationof a treated portion that may be modeled with a simulation. The treatedportion includes a well pattern with heat sources 9524 and producers9526. Dashed lines 9528 correspond to three planes of symmetry that maydivide the pattern into six equivalent sections. Solid lines betweenheat sources 9524 merely depict the pattern of heat sources (i.e., thesolid lines do not represent actual equipment between the heat sources).In some embodiments, a geomechanical model of the pattern may includeone of the six symmetry segments.

[0741]FIG. 36 depicts a horizontal cross section of a model of aformation for use by a simulation method according to one embodiment.The model includes grid elements 9530. Treated portion 9532 is locatedin the lower left corner of the model. Grid elements in the treatedportion may be sufficiently small to take into account the largevariations in conditions in the treated portion. In addition, distance9537 and distance 9539 may be sufficiently large such that thedeformation furthest from the treated portion is substantiallynegligible. Alternatively, a model may be approximated by a shape, suchas a cylinder. The diameter and height of the cylinder may correspond tothe size and height of the treated portion.

[0742] In certain embodiments, heat sources may be modeled by linesources that inject heat at a fixed rate. The heat sources may generatea reasonably accurate temperature distribution in the vicinity of theheat sources. Alternatively, a time-dependent temperature distributionmay be imposed as an average boundary condition.

[0743]FIG. 37 illustrates a flow chart of an embodiment of method 9532for modeling deformation due to treatment of an oil shale formation insitu. The method may include providing at least one property 9534 of theformation to a computer system. The formation may include a treatedportion and an untreated portion. Properties may include mechanical,chemical, thermal, and physical properties of the portions of theformation. For example, the mechanical properties may includecompressive strength, confining pressure, creep parameters, elasticmodulus, Poisson's ratio, cohesion stress, friction angle, and capeccentricity. Thermal and physical properties may include a coefficientof thermal expansion, volumetric heat capacity, and thermalconductivity. Properties may also include the porosity, permeability,saturation, compressibility, and density of the formation. Chemicalproperties may include, for example, the richness and/or organic contentof the portions of the formation.

[0744] In addition, at least one operating condition 9535 may beprovided to the computer system. For instance, operating conditions mayinclude, but are not limited to, pressure, temperature, process time,rate of pressure increase, heating rate, and characteristics of the wellpattern. In addition, an operating condition may include the overburdenthickness and thickness and width or radius of the treated portion ofthe formation. An operating condition may also include untreatedportions between treated portions of the formation, along with thehorizontal distance between treated portions of a formation.

[0745] In certain embodiments, the properties may include initialproperties of the formation. Furthermore, the model may includerelationships for the dependence of the mechanical, thermal, andphysical properties on conditions such as temperature, pressure, andrichness in the portions of the formation. For example, the compressivestrength in the treated portion of the formation may be a function ofrichness, temperature, and pressure. The volumetric heat capacity maydepend on the richness and the coefficient of thermal expansion may be afunction of the temperature and richness. Additionally, thepermeability, porosity, and density may be dependent upon the richnessof the formation.

[0746] In some embodiments, physical and mechanical properties for amodel of a formation may be assessed from samples extracted from ageological formation targeted for treatment. Properties of the samplesmay be measured at various temperatures and pressures. For example,mechanical properties may be measured using uniaxial, triaxial, andcreep experiments. In addition, chemical properties (e.g., richness) ofthe samples may also be measured. Richness of the samples may bemeasured by the Fischer Assay method. The dependence of properties ontemperature, pressure, and richness may then be assessed from themeasurements. In certain embodiments, the properties may be mapped on toa model using known sample locations. For instance, FIG. 38 depicts aprofile of richness versus depth in a model of an oil shale formation.The treated portion is represented by region 9545. Similarly, theoverburden and base rock are represented by region 9547 and region 9549,respectively. In FIG. 38, richness is measured in m³ of kerogen permetric ton of oil shale.

[0747] In certain embodiments, assessing deformation using a simulationmethod may require a material or constitutive model. A constitutivemodel relates the stress in the formation to the strain or displacement.Mechanical properties may be entered into a suitable constitutive modelto calculate the deformation of the formation. In one embodiment, theDrucker-Prager-with-cap material model may be used to model thetime-independent deformation of the formation.

[0748] In an embodiment, the time-dependent creep or secondary creepstrain of the formation may also be modeled. For example, thetime-dependent creep in a formation may be modeled with a power law inEQN. 22:

ε=C×(σ₁−σ₃)^(D) ×t  (22)

[0749] where ε is the secondary creep strain, C is a creep multiplier,σ₁ is the axial stress, σ₃ is the confining pressure, D is a stressexponent, and t is the time. The values of C and D may be obtained fromfitting experimental data. In one embodiment, the creep rate may beexpressed by EQN. 23:

dε/dt=A×(σ₁/σ_(u))^(D)  (23)

[0750] where A is a multiplier obtained from fitting experimental dataand σ_(u) is the ultimate strength in uniaxial compression.

[0751] Additionally, the method shown in FIG. 37 may further includeassessing 9536 at least one process characteristic 9538 of the treatedportion of the formation. At least one process characteristic 9538 mayinclude a pore pressure distribution, a heat input rate, or a timedependent temperature distribution in the treated portion of theformation.

[0752] At least one process characteristic may be assessed by asimulation method. For example, a heat input rate may be estimated usinga body-fitted finite difference simulation package such as FLUENT.Similarly, the pore pressure distribution may be assessed from aspace-fitted or body-fitted simulation method such as STARS. In otherembodiments, the pore pressure may be assessed by a finite elementsimulation method such as ABAQUS. The finite element simulation methodmay employ line sinks of fluid to simulate the performance of productionwells.

[0753] Alternatively, process characteristics such as temperaturedistribution and pore pressure distribution may be approximated by othermeans. For example, the temperature distribution may be imposed as anaverage boundary condition in the calculation of deformationcharacteristics. The temperature distribution may be estimated fromresults of detailed calculations of a heating rate of a formation. Forexample, a treated portion may be heated to a pyrolyzation temperaturefor a specified period of time by heat sources and the temperaturedistribution assessed during heating of the treated portion. In anembodiment, the heat sources may be uniformly distributed and inject aconstant amount of heat. The temperature distribution inside most of thetreated portion may be substantially uniform during the specified periodof time. Some heat may be allowed to diffuse from the treated portioninto the overburden, base rock, and lateral rock. The treated portionmay be maintained at a selected temperature for a selected period oftime after the specified period of time by injecting heat from the heatsources as needed.

[0754] Similarly, the pore pressure distribution may also be imposed asan average boundary condition. The initial pore pressure distributionmay be assumed to be lithostatic. The pore pressure distribution maythen be gradually reduced to a selected pressure during the remainder ofthe simulation of the deformation characteristics.

[0755] In some embodiments, the method may include assessing at leastone deformation characteristic 9542 of the formation using simulationmethod 9540 on the computer system as a function of time. At least onedeformation characteristic may be assessed from at least one property9534, at least one process characteristic 9538, and at least oneoperating condition 9535. In certain embodiments, process characteristic9538 may be assessed by a simulation or process characteristic 9538 maybe measured. Deformation characteristics may include, but are notlimited to, subsidence, compaction, heave, and shear deformation in theformation.

[0756] Simulation method 9540 may be a finite element simulation methodfor calculating elastic, plastic, and time dependent behavior ofmaterials. For example, ABAQUS is a commercially available finiteelement simulation method from Hibbitt, Karlsson & Sorensen, Inc.located in Pawtucket, R.I. ABAQUS is capable of describing the elastic,plastic, and time dependent (creep) behavior of a broad class ofmaterials such as mineral matter, soils, and metals. In general, ABAQUSmay treat materials whose properties may be specified by user-definedconstitutive laws. ABAQUS may also calculate heat transfer and treat theeffect of pore pressure variations on rock deformation.

[0757] Computer simulations may be used to assess operating conditionsof an in situ process in a formation that may result in desireddeformation characteristics. FIG. 39 illustrates a flow chart of anembodiment of method 9544 for designing and controlling an in situprocess using a computer system. The method may include providing to thecomputer system at least one set of operating conditions 9546 for the insitu process. For instance, operating conditions may include pressure,temperature, process time, rate of pressure increase, heating rate,characteristics of the well pattern, the overburden thickness, thicknessand width of the treated portion of the formation and/or untreatedportions between treated portions of the formation, and the horizontaldistance between treated portions of a formation.

[0758] In addition, at least one desired deformation characteristic 9548for the in situ process may be provided to the computer system. Thedesired deformation characteristic may be a selected subsidence,selected heave, selected compaction, or selected shear deformation. Insome embodiments, at least one additional operating condition 9551 maybe assessed using simulation method 9550 that achieves at least onedesired deformation characteristic 9548. A desired deformationcharacteristic may be a value that does not adversely effect theoperation of an in situ process. For example, a minimum overburdennecessary to achieve a desired maximum value of subsidence may beassessed. In an embodiment, at least one additional operating condition9551 may be used to operate an in situ process 9552.

[0759] In one embodiment, operating conditions to obtain desireddeformation characteristics may be assessed from simulations of an insitu process based on multiple operating conditions. FIG. 40 illustratesa flow chart of an embodiment of method 9554 for assessing operatingconditions to obtain desired deformation characteristics. The method mayinclude providing one or more values of at least one operating condition9556 to a computer system for use as input to simulation method 9558.The simulation method may be a finite element simulation method forcalculating elastic, plastic, and creep behavior.

[0760] In some embodiments, the method may further include assessing oneor more values of deformation characteristics 9560 using simulationmethod 9558 based on the one or more values of at least one operatingcondition 9556. In one embodiment, a value of at least one deformationcharacteristic may include the deformation characteristic as a functionof time. A desired value of at least one deformation characteristic 9564for the in situ process may also be provided to the computer system. Anembodiment of the method may include assessing 9562 desired value of atleast one operating condition 9566 to achieve desired value of at leastone deformation characteristic 9564.

[0761] Desired value of at least one operating condition 9566 may beassessed from the values of at least one deformation characteristic 9560and the values of at least one operating condition 9556. For example,desired value 9566 may be obtained by interpolation of values 9560 andvalues 9556. In some embodiments, a value of at least one deformationcharacteristic may be assessed 9565 from the desired value of at leastone operating condition 9566 using simulation method 9558. In someembodiments, an operating condition to achieve a desired deformationcharacteristic may be assessed by comparing a deformation characteristicas a function of time for different operating conditions.

[0762] In an alternate embodiment, a desired value of at least oneoperating condition to achieve the desired value of at least onedeformation characteristic may be assessed using a relationship betweenat least one deformation characteristic and at least one operatingcondition of the in situ process. The relationship may be assessed usinga simulation method. Such relationship may be stored on a databaseaccessible by the computer system. The relationship may include one ormore values of at least one deformation characteristic and correspondingvalues of at least one operating condition. Alternatively, therelationship may be an analytical function.

[0763] Simulations have been used to investigate the effect of variousoperating conditions on the deformation characteristics of an oil shaleformation. In one set of simulations, the formation was modeled aseither a cylinder or a rectangular slab. In the case of a cylinder, themodel of the formation is described by a thickness of the treatedportion, a radius, and a thickness of the overburden. The rectangularslab is described by a width rather than a radius and by a thickness ofthe treated section and overburden. FIG. 41 illustrates the influence ofoperating pressure on subsidence in a cylindrical model of a formationfrom a finite element simulation. The thickness of the treated portionis 189 m, the radius of the treated portion is 305 m, and the overburdenthickness is 201 m. FIG. 41 shows the vertical surface displacement inmeters over a period of years. Curve 9568 corresponds to an operatingpressure of 27.6 bars absolute and curve 9569 to an operating pressureof 6.9 bars absolute. It is to be understood that the surfacedisplacements set forth in FIG. 41 are only illustrative (actual surfacedisplacements will generally differ from those shown in FIG. 41). FIG.41 demonstrates, however, that increasing the operating pressure maysubstantially reduce subsidence.

[0764]FIGS. 42 and 43 illustrate the influence of the use of anuntreated portion between two treated portions. FIG. 42 is thesubsidence in a rectangular slab model with a treated portion thicknessof 189 m, treated portion width of 649 m, and overburden thickness of201 m. FIG. 43 represents the subsidence in a rectangular slab modelwith two treated portions separated by an untreated portion, as picturedin FIG. 34. The thickness of the treated portion and the overburden arethe same as the model corresponding to FIG. 42. The width of eachtreated portion is one half of the width of the treated portion of themodel in FIG. 42. Therefore, the total width of the treated portions isthe same for each model. The operating pressure in each case is 6.9 barsabsolute. As with FIG. 41, the surface displacements in FIGS. 42 and 43are only illustrative. A comparison of FIGS. 42 and 43, however, showsthat the use of an untreated portion reduces the subsidence by about25%. In addition, the initial heave is also reduced.

[0765] In another set of simulations, the calculation of the sheardeformation in a treated oil shale formation was demonstrated. The modelincluded a symmetry element of a pattern of heat sources and producerwells. Boundary conditions imposed in the model were such that thevertical planes bounding the formation were symmetry planes. FIG. 44represents the shear deformation of the formation at the location ofselected heat sources as a function of. depth. Curve 9570 and curve 9571represent the shear deformation as a function of depth at 10 months and12 months, respectively. The curves, which correspond to the predictedshape of the heat injection wells, show that shear deformation increaseswith depth in the formation.

[0766] In certain embodiments, a computer system may be used to operatean in situ process for treating an oil shale formation. The in situprocess may include providing heat from one or more heat sources to atleast one portion of the formation. In addition, the in situ process mayalso include allowing the heat to transfer from the one or more heatsources to a selected section of the formation. FIG. 45 illustratesmethod 9480 for operating an in situ process using a computer system.The method may include operating in situ process 9482 using one or moreoperating parameters. Operating parameters may include properties of theformation, such as heat capacity, density, permeability, thermalconductivity, porosity, and/or chemical reaction data. In addition,operating parameters may include operating conditions. Operatingconditions may include, but are not limited to, thickness and area ofheated portion of the formation, pressure, temperature, heating rate,heat input rate, process time, production rate, time to obtain a givenproduction rate, weight percentage of gases, and/or peripheral waterrecovery or injection. Operating conditions may also includecharacteristics of the well pattern such as producer well location,producer well orientation, ratio of producer wells to heater wells,heater well spacing, type of heater well pattern, heater wellorientation, and/or distance between an overburden and horizontal heaterwells. Operating parameters may also include mechanical properties ofthe formation. Operating parameters may include deformationcharacteristics, such as fracture, strain, subsidence, heave,compaction, and/or shear deformation.

[0767] In certain embodiments, at least one operating parameter 9484 ofin situ process 9482 may be provided to computer system 9486. Computersystem 9486 may be at or near in situ process 9482. Alternatively,computer system 9486 may be at a location remote from in situ process9482. The computer system may include a first simulation method forsimulating a model of in situ process 9482. In one embodiment, the firstsimulation method may include method 9470 illustrated in FIG. 22, method9360 illustrated in FIG. 24, method 8630 illustrated in FIG. 26, method9390 illustrated in FIG. 27, method 9405 illustrated in FIG. 28, method9430 illustrated in FIG. 29, and/or method 9450 illustrated in FIG. 30.The first simulation method may include a body-fitted finite differencesimulation method such as FLUENT or space-fitted finite differencesimulation method such as STARS. The first simulation method may performa reservoir simulation. A reservoir simulation method may be used todetermine operating parameters including, but not limited to, pressure,temperature, heating rate, heat input rate, process time, productionrate, time to obtain a given production rate, weight percentage ofgases, and peripheral water recovery or injection.

[0768] In an embodiment, the first simulation method may also calculatedeformation in a formation. A simulation method for calculatingdeformation characteristics may include a finite element simulationmethod such as ABAQUS. The first simulation method may calculatefracture progression, strain, subsidence, heave, compaction, and sheardeformation. A simulation method used for calculating deformationcharacteristics may include method 9532 illustrated in FIG. 37 and/ormethod 9554 illustrated in FIG. 40.

[0769] The method may further include using at least one parameter 9484with a first simulation method and the computer system to provideassessed information 9488 about in situ process 9482. Operatingparameters from the simulation may be compared to operating parametersof in situ process 9482. Assessed information from a simulation mayinclude a simulated relationship between one or more operatingparameters with at least one parameter 9484. For example, the assessedinformation may include a relationship between operating parameters suchas pressure, temperature, heating input rate, or heating rate andoperating parameters relating to product quality.

[0770] In some embodiments, assessed information may includeinconsistencies between operating parameters from simulation andoperating parameters from in situ process 9482. For example, thetemperature, pressure, product quality, or production rate from thefirst simulation method may differ from in situ process 9482. The sourceof the inconsistencies may be assessed from the operating parametersprovided by simulation. The source of the inconsistencies may includedifferences between certain properties used in a simulated model of insitu process 9482 and in situ process 9482. Certain properties mayinclude, but are not limited to, thermal conductivity, heat capacity,density, permeability, or chemical reaction data. Certain properties mayalso include mechanical properties such as compressive strength,confining pressure, creep parameters, elastic modulus, Poisson's ratio,cohesion stress, friction angle, and cap eccentricity.

[0771] In one embodiment, assessed information may include adjustmentsin one or more operating parameters of in situ process 9482. Theadjustments may compensate for inconsistencies between simulatedoperating parameters and operating parameters from in situ process 9482.Adjustments may be assessed from a simulated relationship between atleast one parameter 9484 and one or more operating parameters.

[0772] For example, an in situ process may have a particular hydrocarbonfluid production rate, e.g., 1 m³/day, after a particular period of time(e.g., 90 days). A theoretical temperature at an observation well (e.g.,100° C.) may be calculated using given properties of the formation.However, a measured temperature at an observation well (e.g., 80° C.)may be lower than the theoretical temperature. A simulation on acomputer system may be performed using the measured temperature. Thesimulation may provide operating parameters of the in situ process thatcorrespond to the measured temperature. The operating parameters fromsimulation may be used to assess a relationship between, for example,temperature or heat input rate and the production rate of the in situprocess. The relationship may indicate that the heat capacity or thermalconductivity of the formation used in the simulation is inconsistentwith the formation.

[0773] In some embodiments, the method may further include usingassessed information 9488 to operate in situ process 9482. As usedherein, “operate” refers to controlling or changing operating conditionsof an in situ process. For example, the assessed information mayindicate that the thermal conductivity of the formation in the aboveexample is lower than the thermal conductivity used in the simulation.Therefore, the heat input rate to in situ process 9482 may be increasedto operate at the theoretical temperature.

[0774] In other embodiments, the method may include obtaining 9492information 9494 from a second simulation method and the computer systemusing assessed information 9488 and desired parameter 9490. In oneembodiment, the first simulation method may be the same as the secondsimulation method. In another embodiment, the first and secondsimulation methods may be different. Simulations may provide arelationship between at least one operating parameter and at least oneother parameter. Additionally, obtained information 9494 may be used tooperate in situ process 9482.

[0775] Obtained information 9494 may include at least one operatingparameter for use in the in situ process that achieves the desiredparameter. In one embodiment, simulation method 9450 illustrated in FIG.30 may be used to obtain at least one operating parameter that achievesthe desired parameter. For example, a desired hydrocarbon fluidproduction rate for an in situ process may be 6 m³/day. One or moresimulations may be used to determine the operating parameters necessaryto achieve a hydrocarbon fluid production rate of 6 m³/day. In someembodiments, model parameters used by simulation method 9450 may becalibrated to account for differences observed between simulations andin situ process 9482. In one embodiment, simulation method 9390illustrated in FIG. 27 may be used to calibrate model parameters. Inanother embodiment, simulation method 9554 illustrated in FIG. 40 may beused to obtain at least one operating parameter that achieves a desireddeformation characteristic.

[0776]FIG. 46 illustrates a schematic of an embodiment for controllingin situ process 9701 in a formation using a computer simulation method.In situ process 9701 may include sensor 9702 for monitoring operatingparameters. Sensor 9702 may be located in a barrier well, a monitoringwell, a production well, or a heater well. Sensor 9702 may monitoroperating parameters such as subsurface and surface conditions in theformation. Subsurface conditions may include pressure, temperature,product quality, and deformation characteristics, such as fractureprogression. Sensor 9702 may also monitor surface data such as pumpstatus (i.e., on or off), fluid flow rate, surface pressure/temperature,and heater power. The surface data may be monitored with instrumentsplaced at a well.

[0777] In addition, at least one operating parameter 9704 measured bysensor 9702 may be provided to local computer system 9708.Alternatively, operating parameter 9704 may be provided to remotecomputer system 9706. Computer system 9706 may be, for example, apersonal desktop computer system, a laptop, or personal digitalassistant such as a palm pilot. FIG. 47 illustrates several ways thatinformation such as operating parameter 9704 may be transmitted from insitu process 9701 to remote computer system 9706. Information may betransmitted by means of internet 9718, hardwire telephone lines 9720,and wireless communications 9722. Wireless communications 9722 mayinclude transmission via satellite 9724.

[0778] In some embodiments, operating parameter 9704 may be provided tocomputer system 9708 or 9706 automatically during the treatment of aformation. Computer systems 9706 and 9708 may include a simulationmethod for simulating a model of the in situ treatment process 9701. Thesimulation method may be used to obtain information 9710 about the insitu process.

[0779] In an embodiment, a simulation of in situ process 9701 may beperformed manually at a desired time. Alternatively, a simulation may beperformed automatically when a desired condition is met. For instance, asimulation may be performed when one or more operating parameters reach,or fail to reach, a particular value at a particular time. For example,a simulation may be performed when the production rate fails to reach aparticular value at a particular time.

[0780] In some embodiments, information 9710 relating to in situ process9701 may be provided automatically by computer system 9706 or 9708 foruse in controlling in situ process 9701. Information 9710 may includeinstructions relating to control of in situ process 9701. Information9710 may be transmitted from computer system 9706 via internet,hardwire, wireless, or satellite transmission as illustrated in FIG. 47.Information 9710 may be provided to computer system 9712. Computersystem 9712 may also be at a location remote from the in situ process.Computer system 9712 may process information 9710 for use in controllingin situ process 9701. For example, computer system 9712 may useinformation 9710 to determine adjustments in one or more operatingparameters. Computer system 9712 may then automatically adjust 9716 oneor more operating parameters of in situ process 9701. Alternatively, oneor more operating parameters of in situ process 9701 may be displayedand then, optionally, adjusted manually 9714.

[0781]FIG. 48 illustrates a schematic of an embodiment for controllingin situ process 9701 in a formation using information 9710. Information9710 may be obtained using a simulation method and a computer system.Information 9710 may be provided to computer system 9712. Information9710 may include information that relates to adjusting one or moreoperating parameters. Output 9713 from computer system 9712 may beprovided to display 9722, data storage 9724, or surface facility 9723.Output 9713 may also be used to automatically control conditions in theformation by adjusting one or more operating parameters. Output 9713 mayinclude instructions to adjust pump status and flow rate at a barrierwell 9726, adjust pump status and flow rate at a production well 9728,and/or adjust the heater power at a heater well 9730. Output 9713 mayalso include instructions to heating pattern 9732 of in situ process9701. For example, an instruction may be to add one or more heater wellsat particular locations. In addition, output 9713 may includeinstructions to shut-in the formation 9734.

[0782] Alternatively, output 9713 may be viewed by operators of the insitu process on display 9722. The operators may then use output 9713 tomanually adjust one or more operating parameters.

[0783]FIG. 49 illustrates a schematic of an embodiment for controllingin situ process 9701 in a formation using a simulation method and acomputer system. At least one operating parameter 9704 from in situprocess 9701 may be provided to computer system 9736. Computer system9736 may include a simulation method for simulating a model of in situprocess 9701. Computer system 9736 may use the simulation method toobtain information 9738 about in situ process 9701. Information 9738 maybe provided to data storage 9740, display 9742, and analysis 9743. In anembodiment, information 9738 may be automatically provided to in situprocess 9701. Information 9738 may then be used to operate in situprocess 9701.

[0784] Analysis 9743 may include review of information 9738 and/or useof information 9738 to operate in situ process 9701. Analysis 9743 mayinclude obtaining additional information 9750 using one or moresimulations 9746 of in situ process 9701. One or more simulations may beused to obtain additional or modified model parameters of in situprocess 9701. The additional or modified model parameters may be used tofurther assess in situ process 9701. Simulation method 9390 illustratedin FIG. 27 may be used to determine additional or modified modelparameters. Method 9390 may use at least one operating parameter 9704and information 9738 to calibrate model parameters. For example, atleast one operating parameter 9704 may be compared to at least onesimulated operating parameter. Model parameters may be modified suchthat at least one simulated operating parameter matches or approximatesat least one operating parameter 9704.

[0785] In an embodiment, analysis 9743 may include obtaining 9744additional information 9748 about properties of in situ process 9701.Properties may include, for example, thermal conductivity, heatcapacity, porosity, or permeability of one or more portions of theformation. Properties may also include chemical reaction data such as,chemical reactions, chemical components, and chemical reactionparameters. Properties may be obtained from the literature or from fieldor laboratory experiments. For example, properties of core samples ofthe treated formation may be measured in a laboratory. Additionalinformation 9748 may be used to operate in situ process 9701.Alternatively, additional information 9743 may be used in one or moresimulations 9746 to obtain additional information 9750. For example,additional information 9750 may include one or more operating parametersthat may be used to operate in situ process 9701 with a desiredoperating parameter. In one embodiment, method 9450 illustrated in FIG.30 may be used to determine operating parameters to achieve a desiredparameter. The operating parameters may then be used to operate in situprocess 9701.

[0786] An in situ process for treating a formation may include treatinga selected section of the formation with a minimum average overburdenthickness. The minimum average overburden thickness may depend on a typeof hydrocarbon resource and geological formation surrounding thehydrocarbon resource. An overburden may, in some embodiments, besubstantially impermeable so that fluids produced in the selectedsection are inhibited from passing to the ground surface through theoverburden. A minimum overburden thickness may be determined as theminimum overburden needed to inhibit the escape of fluids produced inthe formation and to inhibit breakthrough to the surface due toincreased pressure within the formation during in the situ conversionprocess. Determining this minimum overburden thickness may be dependenton, for example, composition of the overburden, maximum pressure to bereached in the formation during the in situ conversion process,permeability of the overburden, composition of fluids produced in theformation, and/or temperatures in the formation or overburden. A ratioof overburden thickness to hydrocarbon resource thickness may be usedduring selection of resources to produce using an in situ thermalconversion process.

[0787] Selected factors may be used to determine a minimum overburdenthickness. These selected factors may include overall thickness of theoverburden, lithology and/or rock properties of the overburden, earthstresses, expected extent of subsidence and/or reservoir compaction, apressure of a process to be used in the formation, and extent andconnectivity of natural fracture systems surrounding the formation.

[0788] For oil shale, a minimum overburden thickness may be about 100 mor between about 25 m and 300 m. A minimum overburden to resourcethickness may be between about 0.25:1 and 100:1.

[0789]FIG. 50 illustrates a flow chart of a computer-implemented methodfor determining a selected overburden thickness. Selected sectionproperties 6366 may be input into computational system 6250. Propertiesof the selected section may include type of formation, density,permeability, porosity, earth stresses, etc. Selected section properties6366 may be used by a software executable to determine minimumoverburden thickness 6368 for the selected section. The softwareexecutable may be, for example, ABAQUS. The software executable mayincorporate selected factors. Computational system 6250 may also run asimulation to determine minimum overburden thickness 6368. The minimumoverburden thickness may be determined so that fractures that allowformation fluid to pass to the ground surface will not form within theoverburden during an in situ process. A formation may be selected fortreatment by computational system 6250 based on properties of theformation and/or properties of the overburden as determined herein.Overburden properties 6364 may also be input into computational system6250. Properties of the overburden may include a type of material in theoverburden, density of the overburden, permeability of the overburden,earth stresses, etc. Computational system 6250 may also be used todetermine operating conditions and/or control operating conditions foran in situ process of treating a formation.

[0790] Heating of the formation may be monitored during an in situconversion process. Monitoring heating of a selected section may includecontinuously monitoring acoustical data associated with the selectedsection. Acoustical data may include seismic data or any acoustical datathat may be measured, for example, using geophones, hydrophones, orother acoustical sensors. In an embodiment, a continuous acousticalmonitoring system can be used to monitor (e.g., intermittently orconstantly) the formation. The formation can be monitored (e.g., usinggeophones at 2 kilohertz, recording measurements every ⅛ of amillisecond) for undesirable formation conditions. In an embodiment, acontinuous acoustical monitoring system may be obtained from OyoInstruments (Houston, Tex.).

[0791] Acoustical data may be acquired by recording information usingunderground acoustical sensors located within and/or proximate a treatedformation area. Acoustical data may be used to determine a type and/orlocation of fractures developing within the selected section. Acousticaldata may be input into a computational system to determine the typeand/or location of fractures. Also, heating profiles of the formation orselected section may be determined by the computational system using theacoustical data. The computational system may run a software executableto process the acoustical data. The computational system may be used todetermine a set of operating conditions for treating the formation insitu. The computational system may also be used to control the set ofoperating conditions for treating the formation in situ based on theacoustical data. Other properties, such as a temperature of theformation, may also be input into the computational system.

[0792] An in situ conversion process may be controlled by using some ofthe production wells as injection wells for injection of steam and/orother process modifying fluids (e.g., hydrogen, which may affect aproduct composition through in situ hydrogenation).

[0793] In certain embodiments, it may be possible to use welltechnologies that may operate at high temperatures. These technologiesmay include both sensors and control mechanisms. The heat injectionprofiles and hydrocarbon vapor production may be adjusted on a morediscrete basis. It may be possible to adjust heat profiles andproduction on a bed-by-bed basis or in meter-by-meter increments. Thismay allow the ICP to compensate, for example, for different thermalproperties and/or organic contents in an interbedded lithology. Thus,cold and hot spots may be inhibited from forming, the formation may notbe overpressurized, and/or the integrity of the formation may not behighly stressed, which could cause deformations and/or damage towellbore integrity.

[0794]FIGS. 51 and 52 illustrate schematic diagrams of a plan view and across-sectional representation, respectively, of a zone being treatedusing an in situ conversion process (ICP). The ICP may causemicroseismic failures, or fractures, within the treatment zone fromwhich a seismic wave may be emitted. Treatment zone 6400 may be heatedusing heat provided from heater 6410 placed in heater well 6402.Pressure in treatment zone 6400 may be controlled by producing someformation fluid through heater wells 6402 and/or production wells. Heatfrom heater 6410 may cause failure 6406 in a portion of the formationproximate treatment zone 6400. Failure 6406 may be a localized rockfailure within a rock volume of the formation. Failure 6406 may be aninstantaneous failure. Failure 6406 tends to produce seismic disturbance6408. Seismic disturbance 6408 may be an elastic or microseismicdisturbance that propagates as a body wave in the formation surroundingthe failure. Magnitude and direction of seismic disturbance as measuredby sensors may indicate a type of macro-scale failure that occurs withinthe formation and/or treatment zone 6400. For example, seismicdisturbance 6408 may be evaluated to indicate a location, orientation,and/or extent of one or more macro-scale failures that occurred in theformation due to heat treatment of the treatment zone 6400.

[0795] Seismic disturbance 6408 from one or more failures 6406 may bedetected with one or more sensors 6412. Sensor 6412 may be a geophone,hydrophone, accelerometer, and/or other seismic sensing device. Sensors6412 may be placed in monitoring well 6404 or monitoring wells.Monitoring wells 6404 may be placed in the formation proximate heaterwell 6402 and treatment zone 6400. In certain embodiments, threemonitoring wells 6404 are placed in the formation such that a locationof failure 6406 may be triangulated using sensors 6412 in eachmonitoring well.

[0796] In an in situ conversion process embodiment, sensors 6412 maymeasure a signal of seismic disturbance 6408. The signal may include awave or set of waves emitted from failure 6406. The signals may be usedto determine an approximate location of failure 6406. An approximatetime at which failure 6406 occurred, causing seismic disturbance 6408,may also be determined from the signal. This approximate location andapproximate time of failure 6406 may be used to determine if failure6406 can propagate into an undesired zone of the formation. Theundesired zone may include a water aquifer, a zone of the formationundesired for treatment, overburden 540 of the formation, and/orunderburden 6416 of the formation. An aquifer may also lie aboveoverburden 540 or below underburden 6416. Overburden 540 and/orunderburden 6416 may include one or more rock layers that can befractured and allow formation fluid to undesirably escape from the insitu conversion process. Sensors 6412 may be used to monitor aprogression of failure 6406 (i.e., an increase in extent of the failure)over a period of time.

[0797] In certain embodiments, a location of failure 6406 may be moreprecisely determined using a vertical distribution of sensors 6412 alongeach monitoring well 6404. The vertical distribution of sensors 6412 mayalso include at least one sensor above overburden 540 and/or belowunderburden 6416. The sensors above overburden 540 and/or belowunderburden 6416 may be used to monitor penetration (or an absence ofpenetration) of a failure through the overburden or underburden.

[0798] If failure 6406 may propagate into an undesired zone of theformation, a parameter for treatment of treatment zone 6400 controlledthrough heater well 6402 may be altered to inhibit propagation of thefailure. The parameter of treatment may include a pressure in treatmentzone 6400, a volume (or flow rate) of fluids injected into the treatmentzone or removed from the treatment zone, or a heat input rate fromheater 6410 into the treatment zone.

[0799]FIG. 53 illustrates a flow chart of an embodiment of a method usedto monitor treatment of a formation. Treatment plan 6420 may be providedfor a treatment zone (e.g., treatment zone 6400 in FIGS. 51 and 52).Parameters 6422 for treatment plan 6420 may include, but are not limitedto, pressure in the treatment zone, heating rate of the treatment zone,and average temperature in the treatment zone. Treatment parameters 6422may be controlled to treat through heat sources, production wells,and/or injection wells. A failure or failures may occur during treatmentof the treatment zone for a given set of parameters. Seismicdisturbances that indicate a failure may be detected by sensors placedin one or more monitoring wells in monitoring step 6424. The seismicdisturbances may be used to determine a location, a time, and/or extentof the one or more failures in determination step 6426. Determinationstep 6426 may include imaging the seismic disturbances to determine aspatial location of a failure or failures and/or a time at which thefailure or failures occurred. The location, time, and/or extent of thefailure or failures may be processed to determine if treatmentparameters 6422 may be altered to inhibit the propagation of a failureor failures into an undesired zone of the formation in interpretationstep 6428.

[0800] In an in situ conversion process embodiment, a recording systemmay be used to continuously monitor signals from sensors placed in aformation. The recording system may continuously record the signals fromsensors. The recording system may save the signals as data. The data maybe permanently saved by the recording system. The recording system maysimultaneously monitor signals from sensors. The signals may bemonitored at a selected sampling rate (e.g., about once every 0.25milliseconds). In some embodiments, two recording systems may be used tocontinuously monitor signals from sensors. A recording system may beused to record each signal from the sensors at the selected samplingrate for a desired time period. A controller may be used when therecording system is used to monitor a signal. The controller may be acomputational system or computer. In an embodiment using two or morerecording systems, the controller may direct which recording system isused for a selected time period. The controller may include a globalpositioning satellite (GPS) clock. The GPS clock may be used to providea specific time for a recording system to begin monitoring signals(e.g., a trigger time) and a time period for the monitoring of signals.The controller may provide the specific time for the recording system tobegin monitoring signals to a trigger box. The trigger box may be usedto supply a trigger pulse to a recording system to begin monitoringsignals.

[0801] A storage device may be used to record signals monitored by arecording system. The storage device may include a tape drive (e.g., ahigh-speed high-capacity tape drive) or any device capable of recordingrelatively large amounts of data at very short time intervals. In anembodiment using two recording systems, the storage device may receivedata from the first recording system while the second recording systemis monitoring signals from one or more sensors, or vice versa. Thisenables continuous data coverage so that all or substantially allmicroseismic events that occur will be detected. In some embodiments,heat progress through the formation may be monitored by measuringmicroseismic events caused by heating of various portions of theformation.

[0802] In some embodiments, monitoring heating of a selected section ofthe formation may include electromagnetic monitoring of the selectedsection. Electromagnetic monitoring may include measuring a resistivitybetween at least two electrodes within the selected section. Data fromelectromagnetic monitoring may be input into a computational system andprocessed as described above.

[0803] A relationship between a change in characteristics of formationfluids with temperature in an in situ conversion process may bedeveloped. The relationship may relate the change in characteristicswith temperature to a heating rate and temperature for the formation.The relationship may be used to select a temperature which can be usedin an isothermal experiment to determine a quantity and quality of aproduct produced by ICP in a formation without having to use one or moreslow heating rate experiments. The isothermal experiment may beconducted in a laboratory or similar test facility. The isothermalexperiment may be conducted much more quickly than experiments thatslowly increase temperatures. An appropriate selection of a temperaturefor an isothermal experiment may be significant for prediction ofcharacteristics of formation fluids. The experiment may includeconducting an experiment on a sample of a formation. The experiment mayinclude producing hydrocarbons from the sample.

[0804] For example, first order kinetics may be generally assumed for areaction producing a product. Assuming first order kinetics and a linearheating rate, the change in concentration (a characteristic of aformation fluid being the concentration of a component) with temperaturemay be defined by the equation:

dC/dT=−(k ₀ /m)×e ^((−E/RT)) C;  (24)

[0805] in which C is the concentration of a component, T is temperaturein Kelvin, k₀ is the frequency factor of the reaction, m is the heatingrate, E is the activation energy, and R is the gas constant.

[0806] EQN. 24 may be solved for a concentration at a selectedtemperature based on an initial concentration at a first temperature.The result is the equation: $\begin{matrix}{{C = {C_{0} \times ^{- \frac{k_{0}{RT}^{2}^{- \frac{E}{RT}}}{mE}}}}\quad;} & (25)\end{matrix}$

[0807] in which C is the concentration of a component at temperature Tand C₀ is an initial concentration of the component.

[0808] Substituting EQN. 25 into EQN. 24 yields the expression:$\begin{matrix}{{\frac{C}{T} = {{- \frac{k_{0}C_{0}}{m}} \times ^{({{- \frac{E}{RT}} - {\frac{k_{0}{RT}^{2}}{mE} \times ^{- \frac{E}{RT}}}})}}};} & (26)\end{matrix}$

[0809] which relates the change in concentration C with temperature Tfor first-order kinetics and a linear heating rate.

[0810] Typically, in application of an ICP to an oil shale formation,the heating rate may not be linear due to temperature limitations inheat sources and/or in heater wells. For example, heating may be reducedat higher temperatures so that a temperature in a heater well ismaintained below a desired temperature (e.g., about 650° C.). This mayprovide a non-linear heating rate that is relatively slower than alinear heating rate. The non-linear heating rate may be expressed as:

T=m×t ^(n);  (27)

[0811] in which t is time and n is an exponential decay term for theheating rate, and in which n is typically less than 1 (e.g., about0.75).

[0812] Using EQN. 27 in a first-order kinetics equation gives theexpression: $\begin{matrix}{{C = {C_{0} \times ^{({{- \frac{k_{0}{RT}^{\frac{n + 1}{n}}}{m^{1/n}n}} \times ^{- \frac{E}{RT}}})}}}\quad;} & (28)\end{matrix}$

[0813] which is a generalization of EQN. 25 for a non-linear heatingrate.

[0814] An isothermal experiment may be conducted at a selectedtemperature to determine a quality and a quantity of a product producedusing an ICP in a formation. The selected temperature may be atemperature at which half the initial concentration, C₀, has beenconverted into product (i.e., C/C₀=½). EQN. 28 may be solved for thisvalue, giving the expression: $\begin{matrix}{{{{\ln ( \frac{k_{0}R}{m^{1/n}n} )} - {\ln ( {\ln \quad 2} )}} = {\frac{E}{{RT}_{1/2}} - {\frac{n + 1}{n} \times \ln \quad T_{1/2}}}}\quad;} & (29)\end{matrix}$

[0815] in which T_(1/2) is the selected temperature which corresponds toconverting half of the initial concentration into product.Alternatively, an equation such as EQN. 26 may be used with a heatingrate that approximates a heating rate expected in a temperature rangewhere in situ conversion of hydrocarbons is expected. EQN. 29 may beused to determine a selected temperature based on a heating rate thatmay be expected for ICP in at least a portion of a formation. Theheating rate may be selected based on parameters such as, but notlimited to, heater well spacing, heater well installation economics(e.g., drilling costs, heater costs, etc.), and maximum heater output.At least one property of the formation may also be used to determine theheating rate. At least one property may include, but is not limited to,a type of formation, formation heat capacity, formation depth,permeability, thermal conductivity, and total organic content. Theselected temperature may be used in an isothermal experiment todetermine product quality and/or quantity. The product quality and/orquantity may also be determined at a selected pressure in the isothermalexperiment. The selected pressure may be a pressure used for an ICP. Theselected pressure may be adjusted to produce a desired product qualityand/or quantity in the isothermal experiment. The adjusted selectedpressure may be used in an ICP to produce the desired product qualityand/or quality from the formation.

[0816] In some embodiments, EQN. 29 may be used to determine a heatingrate (m or m^(n)) used in an ICP based on results from an isothermalexperiment at a selected temperature (T_(1/2)). For example, isothermalexperiments may be performed at a variety of temperatures. The selectedtemperature may be chosen as a temperature at which a product of desiredquality and/or quantity is produced. The selected temperature may beused in EQN. 29 to determine the desired heating rate during ICP toproduce a product of the desired quality and/or quantity.

[0817] Alternatively, if a heating rate is estimated, at least in afirst instance, by optimizing costs and incomes such as heater wellcosts and the time required to produce hydrocarbons, then constants foran equation such as EQN. 29 may be determined by data from an experimentwhen the temperature is raised at a constant rate. With the constants ofEQN. 29 estimated and heating rates estimated, a temperature forisothermal experiments may be calculated. Isothermal experiments may beperformed much more quickly than experiments at anticipated heatingrates (i.e., relatively slow heating rates). Thus, the effect ofvariables (such as pressure) and the effect of applying additional gases(such as, for example, steam and hydrogen) may be determined byrelatively fast experiments.

[0818] In an embodiment, an oil shale formation may be heated with anatural distributed combustor system located in the formation. Thegenerated heat may be allowed to transfer to a selected section of theformation. A natural distributed combustor may oxidize hydrocarbons in aformation in the vicinity of a wellbore to provide heat to a selectedsection is of the formation.

[0819] A temperature sufficient to support oxidation may be at leastabout 200° C. or 250° C. The temperature sufficient to support oxidationwill tend to vary depending on many factors (e.g., a composition of thehydrocarbons in the oil shale formation, water content of the formation,and/or type and amount of oxidant). Some water may be removed from theformation prior to heating. For example, the water may be pumped fromthe formation by dewatering wells. The heated portion of the formationmay be near or substantially adjacent to an opening in the oil shaleformation. The opening in the formation may be a heater well formed inthe formation. The heated portion of the oil shale formation may extendradially from the opening to a width of about 0.3 m to about 1.2 m. Thewidth, however, may also be less than about 0.9 m. A width of the heatedportion may vary with time. In certain embodiments, the variance dependson factors including a width of formation necessary to generatesufficient heat during oxidation of carbon to maintain the oxidationreaction without providing heat from an additional heat source.

[0820] After the portion of the formation reaches a temperaturesufficient to support oxidation, an oxidizing fluid may be provided intothe opening to oxidize at least a portion of the hydrocarbons at areaction zone or a heat source zone within the formation. Oxidation ofthe hydrocarbons will generate heat at the reaction zone. The generatedheat will in most embodiments transfer from the reaction zone to apyrolysis zone in the formation. In certain embodiments, the generatedheat transfers at a rate between about 650 watts per meter and 1650watts per meter as measured along a depth of the reaction zone. Uponoxidation of at least some of the hydrocarbons in the formation, energysupplied to the heater for initially heating the formation to thetemperature sufficient to support oxidation may be reduced or turnedoff. Energy input costs may be significantly reduced using naturaldistributed combustors, thereby providing a significantly more efficientsystem for heating the formation.

[0821] In an embodiment, a conduit may be disposed in the opening toprovide oxidizing fluid into the opening. The conduit may have floworifices or other flow control mechanisms (i.e., slits, venturi meters,valves, etc.) to allow the oxidizing fluid to enter the opening. Theterm “orifices” includes openings having a wide variety ofcross-sectional shapes including, but not limited to, circles, ovals,squares, rectangles, triangles, slits, or other regular or irregularshapes. The flow orifices may be critical flow orifices in someembodiments. The flow orifices may provide a substantially constant flowof oxidizing fluid into the opening, regardless of the pressure in theopening.

[0822] In some embodiments, the number of flow orifices may be limitedby the diameter of the orifices and a desired spacing between orificesfor a length of the conduit. For example, as the diameter of theorifices decreases, the number of flow orifices may increase, and viceversa. In addition, as the desired spacing increases, the number of floworifices may decrease, and vice versa. The diameter of the orifices maybe determined by a pressure in the conduit and/or a desired flow ratethrough the orifices. For example, for a flow rate of about 1.7 standardcubic meters per minute and a pressure of about 7 bars absolute, anorifice diameter may be about 1.3 mm with a spacing between orifices ofabout 2 m. Smaller diameter orifices may plug more readily than largerdiameter orifices. Orifices may plug for a variety of reasons. Thereasons may include, but are not limited to, contaminants in the fluidflowing in the conduit and/or solid deposition within or proximate theorifices.

[0823] In some embodiments, the number and diameter of the orifices arechosen such that a more even or nearly uniform heating profile will beobtained along a depth of the opening in the formation. A depth of aheated formation that is intended to have an approximately uniformheating profile may be greater than about 300 m, or even greater thanabout 600 m. Such a depth may vary, however, depending on, for example,a type of formation to be heated and/or a desired production rate.

[0824] In some embodiments, flow orifices may be disposed in a helicalpattern around the conduit within the opening. The flow orifices may bespaced by about 0.3 m to about 3 m between orifices in the helicalpattern. In some embodiments, the spacing may be about 1 m to about 2 mor, for example, about 1.5 m.

[0825] The flow of oxidizing fluid into the opening may be controlledsuch that a rate of oxidation at the reaction zone is controlled.Transfer of heat between incoming oxidant and outgoing oxidationproducts may heat the oxidizing fluid. The transfer of heat may alsomaintain the conduit below a maximum operating temperature of theconduit.

[0826]FIG. 54 illustrates an embodiment of a natural distributedcombustor that may heat an lip, oil shale formation. Conduit 512 may beplaced into opening 514 in hydrocarbon layer 516. Conduit 512 may haveinner conduit 513. Oxidizing fluid source 508 may provide oxidizingfluid 517 into inner conduit 513. Inner conduit 513 may have criticalflow orifices 515 along its length. Critical flow orifices 515 may bedisposed in a helical pattern (or any other pattern) along a length ofinner conduit 513 in opening 514. For example, critical flow orifices515 may be arranged in a helical pattern with a distance of about 1 m toabout 2.5 m between adjacent orifices. Inner conduit 513 may be sealedat the bottom. Oxidizing fluid 517 may be provided into opening 514through critical flow orifices 515 of inner conduit 513.

[0827] Critical flow orifices 515 may be designed such thatsubstantially the same flow rate of oxidizing fluid 517 may be providedthrough each critical flow orifice. Critical flow orifices 515 may alsoprovide substantially uniform flow of oxidizing fluid 517 along a lengthof conduit 512. Such flow may provide substantially uniform heating ofhydrocarbon layer 516 along the length of conduit 512.

[0828] Packing material 542 may enclose conduit 512 in overburden 540 ofthe formation. Packing material 542 may inhibit flow of fluids fromopening 514 to surface 550. Packing material 542 may include anymaterial that inhibits flow of fluids to surface 550 such as cement orconsolidated sand or gravel. A conduit or opening through the packingmay provide a path for oxidation products to reach the surface.

[0829] Oxidation products 519 typically enter conduit 512 from opening514. Oxidation products 519 may include carbon dioxide, oxides ofnitrogen, oxides of sulfur, carbon monoxide, and/or other productsresulting from a reaction of oxygen with hydrocarbons and/or carbon.Oxidation products 519 may be removed through conduit 512 to surface550. Oxidation product 519 may flow along a face of reaction zone 524 inopening 514 until proximate an upper end of opening 514 where oxidationproduct 519 may flow into conduit 512. Oxidation products 519 may alsobe removed through one or more conduits disposed in opening 514 and/orin hydrocarbon layer 516. For example, oxidation products 519 may beremoved through a second conduit disposed in opening 514. Removingoxidation products 519 through a conduit may inhibit oxidation products519 from flowing to a production well disposed in the formation.Critical flow orifices 515 may also inhibit oxidation products 519 fromentering inner conduit 513.

[0830] A flow rate of oxidation product 519 may be balanced with a flowrate of oxidizing fluid 517 such that a substantially constant pressureis maintained within opening 514. For a 100 m length of heated section,a flow rate of oxidizing fluid may be between about 0.5 standard cubicmeters per minute to about 5 standard cubic meters per minute, or about1.0 standard cubic meters per minute to about 4.0 standard cubic metersper minute, or, for example, about 1.7 standard cubic meters per minute.A flow rate of oxidizing fluid into the formation may be incrementallyincreased during use to accommodate expansion of the reaction zone. Apressure in the opening may be, for example, about 8 bars absolute.Oxidizing fluid 517 may oxidize at least a portion of the hydrocarbonsin heated portion 518 of hydrocarbon layer 516 at reaction zone 524.Heated portion 518 may have been initially heated to a temperaturesufficient to support oxidation by an electric heater, as shown in FIG.55. In some embodiments, an electric heater may be placed inside orstrapped to the outside of conduit 513.

[0831] In certain embodiments, controlling the pressure within opening514 may inhibit oxidation product and/or oxidation fluids from flowinginto the pyrolysis zone of the formation. In some instances, pressurewithin opening 514 may be controlled to be slightly greater than apressure in the formation to allow fluid within the opening to pass intothe formation but to inhibit formation of a pressure gradient thatallows the transport of the fluid a significant distance into theformation.

[0832] Although the heat from the oxidation is transferred to theformation, oxidation product 519 (and excess oxidation fluid such asair) may be inhibited from flowing through the formation and/or to aproduction well within the formation. Instead, oxidation product 519and/or excess oxidation fluid may be removed from the formation. In someembodiments, the oxidation product and/or excess oxidation fluid areremoved through conduit 512. Removing oxidation product and/or excessoxidation fluid may allow heat from oxidation reactions to transfer tothe pyrolysis zone without significant amounts of oxidation productand/or excess oxidation fluid entering the pyrolysis zone.

[0833] In certain embodiments, some pyrolysis product near reaction zone524 may be oxidized in reaction zone 524 in addition to the carbon.Oxidation of the pyrolysis product in reaction zone 524 may provideadditional heating of hydrocarbon layer 516. When oxidation of pyrolysisproduct occurs, oxidation product from the oxidation of pyrolysisproduct may be removed near the reaction zone (e.g., through a conduitsuch as conduit 512). Removing the oxidation product of a pyrolysisproduct may inhibit contamination of other pyrolysis products in theformation with oxidation product.

[0834] Conduit 512 may, in some embodiments, remove oxidation product519 from opening 514 in hydrocarbon layer 516. Oxidizing fluid 517 ininner conduit 513 may be heated by heat exchange with conduit 512. Aportion of heat transfer between conduit 512 and inner conduit 513 mayoccur in overburden section 540. Oxidation product 519 may be cooled bytransferring heat to oxidizing fluid 517. Heating the incoming oxidizingfluid 517 tends to improve the efficiency of heating the formation.

[0835] Oxidizing fluid 517 may transport through reaction zone 524, orheat source zone, by gas phase diffusion and/or convection. Diffusion ofoxidizing fluid 517 through reaction zone 524 may be more efficient atthe relatively high temperatures of oxidation. Diffusion of oxidizingfluid 517 may inhibit development of localized overheating and fingeringin the formation. Diffusion of oxidizing fluid 517 through hydrocarbonlayer 516 is generally a mass transfer process. In the absence of anexternal force, a rate of diffusion for oxidizing fluid 517 may dependupon concentration, pressure, and/or temperature of oxidizing fluid 517within hydrocarbon layer 516. The rate of diffusion may also depend uponthe diffusion coefficient of oxidizing fluid 517 through hydrocarbonlayer 516. The diffusion coefficient may be determined by measurement orcalculation based on the kinetic theory of gases. In general, randommotion of oxidizing fluid 517 may transfer the oxidizing fluid throughhydrocarbon layer 516 from a region of high concentration to a region oflow concentration.

[0836] With time, reaction zone 524 may slowly extend radially togreater diameters from opening 514 as hydrocarbons are oxidized.Reaction zone 524 may, in many embodiments, maintain a relativelyconstant width. For an oil shale formation, reaction zone 524 may extendradially about 2 m in the first year and at a lower rate in subsequentyears due to an increase in volume of reaction zone 524 as the reactionzone extends radially. Such a lower rate may be about 1 m per year toabout 1.5 m per year. Reaction zone 524 may extend at slower rates forhydrocarbon rich formations and at faster rates for formations with moreinorganic material since more hydrocarbons per volume are available forcombustion in the hydrocarbon rich formations.

[0837] A flow rate of oxidizing fluid 517 into opening 514 may beincreased as a diameter of reaction zone 524 increases to maintain therate of oxidation per unit volume at a substantially steady state. Thus,a temperature within reaction zone 524 may be maintained substantiallyconstant in some embodiments. The temperature within reaction zone 524may be between about 650° C. to about 900° C. or, for example, about760° C. The temperature may be maintained below a temperature thatresults in production of oxides of nitrogen (NO_(x)). Oxides of nitrogenare often produced at temperatures above about 1200° C.

[0838] The temperature within reaction zone 524 may be varied to achievea desired heating rate of selected section 526. The temperature withinreaction zone 524 may be increased or decreased by increasing ordecreasing a flow rate of oxidizing fluid 517 into opening 514. Atemperature of conduit 512, inner conduit 513, and/or any metallurgicalmaterials within opening 514 may be controlled to not exceed a maximumoperating temperature of the material. Maintaining the temperature belowthe maximum operating temperature of a material may inhibit excessivedeformation and/or corrosion of the material.

[0839] An increase in the diameter of reaction zone 524 may allow forrelatively rapid heating of hydrocarbon layer 516. As the diameter ofreaction zone 524 increases, an amount of heat generated per time inreaction zone 524 may also increase. Increasing an amount of heatgenerated per time in the reaction zone will in many instances increasea heating rate of hydrocarbon layer 516 over a period of time, evenwithout increasing the temperature in the reaction zone or thetemperature at conduit 513. Thus, increased heating may be achieved overtime without installing additional heat sources and without increasingtemperatures adjacent to wellbores. In some embodiments, the heatingrates may be increased while allowing the temperatures to decrease(allowing temperatures to decrease may often lengthen the life of theequipment used).

[0840] By utilizing the carbon in the formation as a fuel, the naturaldistributed combustor may save significantly on energy costs. Thus, aneconomical process may be provided for heating formations that wouldotherwise be economically unsuitable for heating by other types of heatsources. Using natural distributed combustors may allow fewer heaters tobe inserted into a formation for heating a desired volume of theformation as compared to heating the formation using other types of heatsources. Heating a formation using natural distributed combustors mayallow for reduced equipment costs as compared to heating the formationusing other types of heat sources.

[0841] Heat generated at reaction zone 524 may transfer by thermalconduction to selected section 526 of hydrocarbon layer 516. Inaddition, generated heat may transfer from a reaction zone to theselected section to a lesser extent by convective heat transfer.Selected section 526, sometimes referred as the “pyrolysis zone,” may besubstantially adjacent to reaction zone 524. Removing oxidation product(and excess oxidation fluid such as air) may allow the pyrolysis zone toreceive heat from the reaction zone without being exposed to oxidationproduct, or oxidants, that are in the reaction zone. Oxidation productand/or oxidation fluids may cause the formation of undesirable productsif they are present in the pyrolysis zone. Removing oxidation productand/or oxidation fluids may allow a reducing environment to bemaintained in the pyrolysis zone.

[0842] In an in situ conversion process embodiment, natural distributedcombustors may be used to heat a formation. FIG. 54 depicts anembodiment of a natural distributed combustor. A flow of oxidizing fluid517 may be controlled along a length of opening 514 or reaction zone524. Opening 514 may be referred to as an “elongated opening,” such thatreaction zone 524 and opening 514 may have a common boundary along adetermined length of the opening. The flow of oxidizing fluid may becontrolled using one or more orifices 515 (the orifices may be criticalflow orifices). The flow of oxidizing fluid may be controlled by adiameter of orifices 515, a number of orifices 515, and/or by a pressurewithin inner conduit 513 (a pressure behind orifices 515). Controllingthe flow of oxidizing fluid may control a temperature at a face ofreaction zone 524 in opening 514. For example, an increased flow ofoxidizing fluid 517 will tend to increase a temperature at the face ofreaction zone 524. Increasing the flow of oxidizing fluid into theopening tends to increase a rate of oxidation of hydrocarbons in thereaction zone. Since the oxidation of hydrocarbons is an exothermicreaction, increasing the rate of oxidation tends to increase thetemperature in the reaction zone.

[0843] In certain natural distributed combustor embodiments, the flow ofoxidizing fluid 517 may be varied along the length of inner conduit 513(e.g., using critical flow orifices 515) such that the temperature atthe face of reaction zone 524 is variable. The temperature at the faceof reaction zone 524, or within opening 514, may be varied to control arate of heat transfer within reaction zone 524 and/or a heating ratewithin selected section 526. Increasing the temperature at the face ofreaction zone 524 may increase the heating rate within selected section526. A property of oxidation product 519 may be monitored (e.g., oxygencontent, nitrogen content, temperature, etc.). The property of oxidationproduct 519 may be monitored and used to control input properties (e.g.,oxidizing fluid input) into the natural distributed combustor.

[0844] A rate of diffusion of oxidizing fluid 517 through reaction zone524 may vary with a temperature of and adjacent to the reaction zone. Ingeneral, the higher the temperature, the faster a gas will diffusebecause of the increased energy in the gas. A temperature within theopening may be assessed (e.g., measured by a thermocouple) and relatedto a temperature of the reaction zone. The temperature within theopening may be controlled by controlling the flow of oxidizing fluidinto the opening from inner conduit 513. For example, increasing a flowof oxidizing fluid into the opening may increase the temperature withinthe opening. Decreasing the flow of oxidizing fluid into the opening maydecrease the temperature within the opening. In an embodiment, a flow ofoxidizing fluid may be increased until a selected temperature below themetallurgical temperature limits of the equipment being used is reached.For example, the flow of oxidizing fluid can be increased until aworking temperature limit of a metal used in a conduit placed in theopening is reached. The temperature of the metal may be directlymeasured using a thermocouple or other temperature measurement device.

[0845] In a natural distributed combustor embodiment, production ofcarbon dioxide within reaction zone 524 may be inhibited. An increase ina concentration of hydrogen in the reaction zone may inhibit productionof carbon dioxide within the reaction zone. The concentration ofhydrogen may be increased by transferring hydrogen into the reactionzone. In an embodiment, hydrogen may be transferred into the reactionzone from selected section 526. Hydrogen may be produced during thepyrolysis of hydrocarbons in the selected section. Hydrogen may transferby diffusion and/or convection into the reaction zone from the selectedsection. In addition, additional hydrogen may be provided into opening514 or another opening in the formation through a conduit placed in theopening. The additional hydrogen may transfer into the reaction zonefrom opening 514.

[0846] In some natural distributed combustor embodiments, heat may besupplied to the formation from a second heat source in the wellbore ofthe natural distributed combustor. For example, an electric heater(e.g., an insulated conductor heater or a conductor-in-conduit heater)used to preheat a portion of the formation may also be used to provideheat to the formation along with heat from the natural distributedcombustor. In addition, an additional electric heater may be placed inan opening in the formation to provide additional heat to the formation.The electric heater may be used to provide heat to the formation so thatheat provided from the combination of the electric heater and thenatural distributed combustor is maintained at a constant heat inputrate. Heat input into the formation from the electric heater may bevaried as heat input from the natural distributed combustor varies, orvice versa. Providing heat from more than one type of heat source mayallow for substantially uniform heating of the formation.

[0847] In certain in situ conversion process embodiments, up to 10%,25%, or 50% of the total heat input into the formation may be providedfrom electric heaters. A percentage of heat input into the formationfrom electric heaters may be varied depending on, for example,electricity cost, natural distributed combustor heat input, etc. Heatfrom electric heaters can be used to compensate for low heat output fromnatural distributed combustors to maintain a substantially constantheating rate in the formation. If electrical costs rise, more heat maybe generated from natural distributed combustors to reduce the amount ofheat supplied by electric heaters. In some embodiments, heat fromelectric heaters may vary due to the source of electricity (e.g., solaror wind power). In such an embodiments, more or less heat may beprovided by natural distributed combustors to compensate for changes inelectrical heat input.

[0848] In a heat source embodiment, an electric heater may be used toinhibit a natural distributed combustor from “burning out.” A naturaldistributed combustor may “burn out” if a portion of the formation coolsbelow a temperature sufficient to support combustion. Additional heatfrom the electric heater may be needed to provide heat to the portionand/or another portion of the formation to heat a portion to atemperature sufficient to support oxidation of hydrocarbons and maintainthe natural distributed combustor heating process.

[0849] In some natural distributed combustor embodiments, electricheaters may be used to provide more heat to a formation proximate anupper portion and/or a lower portion of the formation. Using theadditional heat from the electric heaters may compensate for heat lossesin the upper and/or lower portions of the formation. Providingadditional heat with the electric heaters proximate the upper and/orlower portions may produce more uniform heating of the formation. Insome embodiments, electric heaters may be used for similar purposes(e.g., provide heat at upper and/or lower portions, provide supplementalheat, provide heat to maintain a minimum combustion temperature, etc.)in combination with other types of fueled heater, such as flamelessdistributed combustors or downhole combustors.

[0850] In some in situ conversion process embodiments, exhaust fluidsfrom a fueled heater (e.g., a natural distributed combustor, or downholecombustor) may be used in an air compressor located at a surface of theformation proximate an opening used for the fueled heater. The exhaustfluids may be used to drive the air compressor and reduce a costassociated with compressing air for use in the fueled heater.Electricity may also be generated using the exhaust fluids in a turbineor similar device. In some embodiments, fluids (e.g., oxidizing fluidand/or fuel) used for one or more fueled heaters may be provided using acompressor or a series of compressors. A compressor may provideoxidizing fluid and/or fuel for one heater or more than one heater. Inaddition, oxidizing fluid and/or fuel may be provided from a centralizedfacility for use in a single heater or more than one heater.

[0851] Pyrolysis of hydrocarbons, or other heat-controlled processes,may take place in heated selected section 526. Selected section 526 maybe at a temperature between about 270° C. and about 400° C. forpyrolysis. The temperature of selected section 526 may be increased byheat transfer from reaction zone 524.

[0852] A temperature within opening 514 may be monitored with athermocouple disposed in opening 514. Alternatively, a thermocouple maybe coupled to conduit 512 and/or disposed on a face of reaction zone524. Power input or oxidant introduced into the formation may becontrolled based upon the monitored temperature to maintain thetemperature in a selected range. The selected range may vary or bevaried depending on location of the thermocouple, a desired heating rateof hydrocarbon layer 516, and other factors. If a temperature withinopening 514 falls below a minimum temperature of the selectedtemperature range, the flow rate of oxidizing fluid 517 may be increasedto increase combustion and thereby increase the temperature withinopening 514.

[0853] In certain embodiments, one or more natural distributedcombustors may be placed along strike of a hydrocarbon layer and/orhorizontally. Placing natural distributed combustors along strike orhorizontally may reduce pressure differentials along the heated lengthof the heat source. Reduced pressure differentials may make thetemperature generated along a length of the heater more uniform andeasier to control.

[0854] In some embodiments, presence of air or oxygen (O₂) in oxidationproduct 519 may be monitored. Alternatively, an amount of nitrogen,carbon monoxide, carbon dioxide, oxides of nitrogen, oxides of sulfur,etc. may be monitored in oxidation product 519. Monitoring thecomposition and/or quantity of exhaust products (e.g., oxidation product519) may be useful for heat balances, for process diagnostics, processcontrol, etc.

[0855]FIG. 56 illustrates a cross-sectional representation of anembodiment of a natural distributed combustor having a second conduit6200 disposed in opening 514 in hydrocarbon layer 516. Second conduit6200 may be used to remove oxidation products from opening 514. Secondconduit 6200 may have orifices 515 disposed along its length. In certainembodiments, oxidation products are removed from an upper region ofopening 514 through orifices 515 disposed on second conduit 6200.Orifices 515 may be disposed along the length of conduit 6200 such thatmore oxidation products are removed from the upper region of opening514.

[0856] In certain natural distributed combustor embodiments, orifices515 on second conduit 6200 may face away from orifices 515 on conduit513. The orientation may inhibit oxidizing fluid provided throughconduit 513 from passing directly into second conduit 6200.

[0857] In some embodiments, conduit 6200 may have a higher density oforifices 515 (and/or relatively larger diameter orifices 515) towardsthe upper region of opening 514. The preferential removal of oxidationproducts from the upper region of opening 514 may produce asubstantially uniform concentration of oxidizing fluid along the lengthof opening 514. Oxidation products produced from reaction zone 524 tendto be more concentrated proximate the upper region of opening 514. Thelarge concentration of oxidation products 519 in the upper region ofopening 514 tends to dilute a concentration of oxidizing fluid 517 inthe upper region. Removing a significant portion of the moreconcentrated oxidation products from the upper region of opening 514 mayproduce a more uniform concentration of oxidizing fluid 517 throughoutopening 514. Having a more uniform concentration of oxidizing fluidthroughout the opening may produce a more uniform driving force foroxidizing fluid to flow into reaction zone 524. The more uniform drivingforce may produce a more uniform oxidation rate within reaction zone524, and thus produce a more uniform heating rate in selected section526 and/or a more uniform temperature within opening 514.

[0858] In a natural distributed combustor embodiment, the concentrationof air and/or oxygen in the reaction zone may be controlled. A more evendistribution of oxygen (or oxygen concentration) in the reaction zonemay be desirable. The rate of reaction may be controlled as a functionof the rate in which oxygen diffuses in the reaction zone. The rate ofoxygen diffusion correlates to the oxygen concentration. Thus,controlling the oxygen concentration in the reaction zone (e.g., bycontrolling oxidizing fluid flow rates, the removal of oxidationproducts along some or all of the length of the reaction zone, and/orthe distribution of the oxidizing fluid along some or all of the lengthof the reaction zone) may control oxygen diffusion in the reaction zoneand thereby control the reaction rates in the reaction zone.

[0859] In the embodiment shown in FIG. 57, conductor 580 is placed inopening 514. Conductor 580 may extend from first end 6170 of opening 514to second end 6172 of opening 514. In certain embodiments, conductor 580may be placed in opening 514 within hydrocarbon layer 516. One or morelow resistance sections 584 may be coupled to conductor 580 and used inoverburden 540. In some embodiments, conductor 580 and/or low resistancesections 584 may extend above the surface of the formation.

[0860] In some heat source embodiments, an electric current may beapplied to conductor 580 to increase a temperature of the conductor.Heat may transfer from conductor 580 to heated portion 518 ofhydrocarbon layer 516. Heat may transfer from conductor 580 to heatedportion 518 substantially by radiation. Some heat may also transfer byconvection or conduction. Current may be provided to the conductor untila temperature within heated portion 518 is sufficient to support theoxidation of hydrocarbons within the heated portion. As shown in FIG.57, oxidizing fluid may be provided into conductor 580 from oxidizingfluid source 508 at one or both ends 6170, 6172 of opening 514. A flowof the oxidizing fluid from conductor 580 into opening 514 may becontrolled by orifices 515. The orifices may be critical flow orifices.The flow of oxidizing fluid from orifices 515 may be controlled by adiameter of the orifices, a number of orifices, and/or by a pressurewithin conductor 580 (i.e., a pressure behind the orifices).

[0861] Reaction of oxidizing fluids with hydrocarbons in reaction zone524 may generate heat. The rate of heat generated in reaction zone 524may be controlled by a flow rate of the oxidizing fluid into theformation, the rate of diffusion of oxidizing fluid through the reactionzone, and/or a removal rate of oxidation products from the formation. Inan embodiment, oxidation products from the reaction of oxidizing fluidwith hydrocarbons in the formation are removed through one or both endsof opening 514. In some embodiments, a conduit may be placed in opening514 to remove oxidation products. All or portions of the oxidationproducts may be recycled and/or reused in other oxidation type heaters(e.g., natural distributed combustors, surface burners, downholecombustors, etc.). Heat generated in reaction zone 524 may transfer to asurrounding portion (e.g., selected section) of the formation. Thetransfer of heat between reaction zone 524 and selected section may besubstantially by conduction. In certain embodiments, the transferredheat may increase a temperature of the selected section above a minimummobilization temperature of the hydrocarbons and/or a minimum pyrolysistemperature of the hydrocarbons.

[0862] In some heat source embodiments, a conduit may be placed in theopening. The opening may extend through the formation contacting asurface of the earth at a first location and a second location.Oxidizing fluid may be provided to the conduit from the oxidizing fluidsource at the first location and/or the second location after a portionof the formation that has been heated to a temperature sufficient tosupport oxidation of hydrocarbons by the oxidizing fluid.

[0863]FIG. 58 illustrates an embodiment of a section of overburden witha natural distributed combustor as described in FIG. 54. Overburdencasing 541 may be disposed in overburden 540 of hydrocarbon layer 516.Overburden casing 541 may be surrounded by materials (e.g., aninsulating material such as cement) that inhibit heating of overburden540. Overburden casing 541 may be made of a metal material such as, butnot limited to, carbon steel or 304 stainless steel.

[0864] Overburden casing 541 may be placed in reinforcing material 544in overburden 540. Reinforcing material 544 may be, but is not limitedto, cement, gravel, sand, and/or concrete. Packing material 542 may bedisposed between overburden casing 541 and opening 514 in the formation.Packing material 542 may be any substantially non-porous material (e.g.,cement, concrete, grout, etc.). Packing material 542 may inhibit flow offluid outside of conduit 512 and between opening 514 and surface 550.Inner conduit 513 may introduce fluid into opening 514 in hydrocarbonlayer 516. Conduit 512 may remove combustion product (or excessoxidation fluid) from opening 514 in hydrocarbon layer 516. Diameter ofconduit 512 may be determined by an amount of the combustion productproduced by oxidation in the natural distributed combustor. For example,a larger diameter may be required for a greater amount of exhaustproduct produced by the natural distributed combustor heater.

[0865] In some heat source embodiments, a portion of the formationadjacent to a wellbore may be heated to a temperature and at a heatingrate that converts hydrocarbons to coke or char adjacent to the wellboreby a first heat source. Coke and/or char may be formed at temperaturesabove about 400° C. In the presence of an oxidizing fluid, the coke orchar will oxidize. The wellbore may be used as a natural distributedcombustor subsequent to the formation of coke and/or char. Heat may begenerated from the oxidation of coke or char.

[0866]FIG. 59 illustrates an embodiment of a natural distributedcombustor heater. Insulated conductor 562 may be coupled to conduit 532and placed in opening 514 in hydrocarbon layer 516. Insulated conductor562 may be disposed internal to conduit 532 (thereby allowing retrievalof insulated conductor 562), or, alternately, coupled to an externalsurface of conduit 532. Insulating material for the conductor mayinclude, but is not limited to, mineral coating and/or ceramic coating.Conduit 532 may have critical flow orifices 515 disposed along itslength within opening 514. Electrical current may be applied toinsulated conductor 562 to generate radiant heat in opening 514. Conduit532 may serve as a return for current. Insulated conductor 562 may heatportion 518 of hydrocarbon layer 516 to a temperature sufficient tosupport oxidation of hydrocarbons.

[0867] Oxidizing fluid source 508 may provide oxidizing fluid intoconduit 532. Oxidizing fluid may be provided into opening 514 throughcritical flow orifices 515 in conduit 532. Oxidizing fluid may oxidizeat least a portion of the hydrocarbon layer in reaction zone 524. Aportion of heat generated at reaction zone 524 may transfer to selectedsection 526 by convection, radiation, and/or conduction. Oxidationproduct may be removed through a separate conduit placed in opening 514or through opening 543 in overburden casing 541.

[0868]FIG. 60 illustrates an embodiment of a natural distributedcombustor heater with an added fuel conduit. Fuel conduit 536 may beplaced in opening 514. Fuel conduit may be placed adjacent to conduit533 in certain embodiments. Fuel conduit 536 may have critical floworifices 535 along a portion of the length within opening 514. Conduit533 may have critical flow orifices 515 along a portion of the lengthwithin opening 514. The critical flow orifices 535, 515 may bepositioned so that a fuel fluid provided through fuel conduit 536 and anoxidizing fluid provided through conduit 533 do not react to heat thefuel conduit and the conduit. Heat from reaction of the fuel fluid withoxidizing fluid may heat fuel conduit 536 and/or conduit 533 to atemperature sufficient to begin melting metallurgical materials in fuelconduit 536 and/or conduit 533 if the reaction takes place proximatefuel conduit 536 and/or conduit 533. Critical flow orifices 535 on fuelconduit 536 and critical flow orifices 515 on conduit 533 may bepositioned so that the fuel fluid and the oxidizing fluid do not reactproximate the conduits. For example, conduits 536 and 533 may bepositioned such that orifices that spiral around the conduits areoriented in opposite directions.

[0869] Reaction of the fuel fluid and the oxidizing fluid may produceheat. In some embodiments, the fuel fluid may be methane, ethane,hydrogen, or synthesis gas that is generated by in situ conversion inanother part of the formation. The produced heat may heat portion 518 toa temperature sufficient to support oxidation of hydrocarbons. Uponheating of portion 518 to a temperature sufficient to support oxidation,a flow of fuel fluid into opening 514 may be turned down or may beturned off. In some embodiments, the supply of fuel may be continuedthroughout the heating of the formation.

[0870] The oxidizing fluid may oxidize at least a portion of thehydrocarbons at reaction zone 524. Generated heat may transfer heat toselected section 526 by radiation, convection, and/or conduction. Anoxidation product may be removed through a separate conduit placed inopening 514 or through opening 543 in overburden casing 541.

[0871]FIG. 55 illustrates an embodiment of a system that may heat an oilshale formation. Electric heater 510 may be disposed within opening 514in hydrocarbon layer 516. Opening 514 may be formed through overburden540 into hydrocarbon layer 516. Opening 514 may be at least about 5 cmin diameter. Opening 514 may, as an example, have a diameter of about 13cm. Electric heater 510 may heat at least portion 518 of hydrocarbonlayer 516 to a temperature sufficient to support oxidation (e.g., about260° C.). Portion 518 may have a width of about 1 m. An oxidizing fluidmay be provided into the opening through conduit 512 or any otherappropriate fluid transfer mechanism. Conduit 512 may have critical floworifices 515 disposed along a length of the conduit.

[0872] Conduit 512 may be a pipe or tube that provides the oxidizingfluid into opening 514 from oxidizing fluid source 508. In anembodiment, a portion of conduit 512 that may be exposed to hightemperatures is a stainless steel tube and a portion of the conduit thatwill not be exposed to high temperatures (i.e., a portion of the tubethat extends through the overburden) is carbon steel. The oxidizingfluid may include air or any other oxygen containing fluid (e.g.,hydrogen peroxide, oxides of nitrogen, ozone). Mixtures of oxidizingfluids may be used. An oxidizing fluid mixture may be a fluid includingfifty percent oxygen and fifty percent nitrogen. In some embodiments,the oxidizing fluid may include compounds that release oxygen whenheated, such as hydrogen peroxide. The oxidizing fluid may oxidize atleast a portion of the hydrocarbons in the formation.

[0873]FIG. 61 illustrates an embodiment of a system that heats an oilshale formation. Heat exchanger 520 may be disposed external to opening514 in hydrocarbon layer 516. Opening 514 may be formed throughoverburden 540 into hydrocarbon layer 516. Heat exchanger 520 mayprovide heat from another surface process, or it may include a heater(e.g., an electric or combustion heater). Oxidizing fluid source 508 mayprovide an oxidizing fluid to heat exchanger 520. Heat exchanger 520 mayheat an oxidizing fluid (e.g., above 200° C. or to a temperaturesufficient to support oxidation of hydrocarbons). The heated oxidizingfluid may be provided into opening 514 through conduit 521. Conduit 521may have critical flow orifices 515 disposed along a length of theconduit. The heated oxidizing fluid may heat, or at least contribute tothe heating of, at least portion 518 of the formation to a temperaturesufficient to support oxidation of hydrocarbons. The oxidizing fluid mayoxidize at least a portion of the hydrocarbons in the formation. Aftertemperature in the formation is sufficient to support oxidation, use ofheat exchanger 520 may be reduced or phased out.

[0874] An embodiment of a natural distributed combustor may include asurface combustor (e.g., a flame-ignited heater). A fuel fluid may beoxidized in the combustor. The oxidized fuel fluid may be provided intoan opening in the formation from the heater through a conduit. Oxidationproducts and unreacted fuel may return to the surface through anotherconduit. In some embodiments, one of the conduits may be placed withinthe other conduit. The oxidized fuel fluid may heat, or contribute tothe heating of, a portion of the formation to a temperature sufficientto support oxidation of hydrocarbons. Upon reaching the temperaturesufficient to support oxidation, the oxidized fuel fluid may be replacedwith an oxidizing fluid. The oxidizing fluid may oxidize at least aportion of the hydrocarbons at a reaction zone within the formation.

[0875] An electric heater may heat a portion of the oil shale formationto a temperature sufficient to support oxidation of hydrocarbons. Theportion may be proximate or substantially adjacent to the opening in theformation. The portion may radially extend a width of less thanapproximately 1 m from the opening. An oxidizing fluid may be providedto the opening for oxidation of hydrocarbons. Oxidation of thehydrocarbons may heat the oil shale formation in a process of naturaldistributed combustion. Electrical current applied to the electricheater may subsequently be reduced or may be turned off. Naturaldistributed combustion may be used in conjunction with an electricheater to provide a reduced input energy cost method to heat the oilshale formation compared to using only an electric heater.

[0876] An insulated conductor heater may be a heater element of a heatsource. In an embodiment of an insulated conductor heater, the insulatedconductor heater is a mineral insulated cable or rod. An insulatedconductor heater may be placed in an opening in an oil shale formation.The insulated conductor heater may be placed in an uncased opening inthe oil shale formation. Placing the heater in an uncased opening in theoil shale formation may allow heat transfer from the heater to theformation by radiation as well as conduction. Using an uncased openingmay facilitate retrieval of the heater from the well, if necessary.Using an uncased opening may significantly reduce heat source capitalcost by eliminating a need for a portion of casing able to withstandhigh temperature conditions. In some heat source embodiments, aninsulated conductor heater may be placed within a casing in theformation; may be cemented within the formation; or may be packed in anopening with sand, gravel, or other fill material. The insulatedconductor heater may be supported on a support member positioned withinthe opening. The support member may be a cable, rod, or a conduit (e.g.,a pipe). The support member may be made of a metal, ceramic, inorganicmaterial, or combinations thereof. Portions of a support member may beexposed to formation fluids and heat during use, so the support membermay be chemically resistant and thermally resistant.

[0877] Ties, spot welds, and/or other types of connectors may be used tocouple the insulated conductor heater to the support member at variouslocations along a length of the insulated conductor heater. The supportmember may be attached to a wellhead at an upper surface of theformation. In an embodiment of an insulated conductor heater, theinsulated conductor heater is designed to have sufficient structuralstrength so that a support member is not needed. The insulated conductorheater will in many instances have some flexibility to inhibit thermalexpansion damage when heated or cooled.

[0878] In certain embodiments, insulated conductor heaters may be placedin wellbores without support members and/or centralizers. An insulatedconductor heater without support members and/or centralizers may have asuitable combination of temperature and corrosion resistance, creepstrength, length, thickness (diameter), and metallurgy that will inhibitfailure of the insulated conductor during use. In some in situconversion embodiments, insulated conductors that are heated to aworking temperature of about 700° C., are less than about 150 m inlength, are made of 310 stainless steel may be used without supportmembers.

[0879]FIG. 62 depicts a perspective view of an end portion of anembodiment of insulated conductor heater 562. An insulated conductorheater may have any desired cross-sectional shape, such as, but notlimited to round (as shown in FIG. 62), triangular, ellipsoidal,rectangular, hexagonal, or irregular shape. An insulated conductorheater may include conductor 575, electrical insulation 576, and sheath577. Conductor 575 may resistively heat when an electrical currentpasses through the conductor. An alternating or direct current may beused to heat conductor 575. In an embodiment, a 60-cycle AC current isused.

[0880] In some embodiments, electrical insulation 576 may inhibitcurrent leakage and arcing to sheath 577. Electrical insulation 576 mayalso thermally conduct heat generated in conductor 575 to sheath 577.Sheath 577 may radiate or conduct heat to the formation. Insulatedconductor heater 562 may be 1000 m or more in length. In an embodimentof an insulated conductor heater, insulated conductor heater 562 mayhave a length from about 15 m to about 950 m. Longer or shorterinsulated conductors may also be used to meet specific applicationneeds. In embodiments of insulated conductor heaters, purchasedinsulated conductor heaters have lengths of about 100 m to 500 m (e.g.,230 m). In certain embodiments, dimensions of sheaths and/or conductorsof an insulated conductor may be selected so that the insulatedconductor has enough strength to be self supporting even at upperworking temperature limits. Such insulated cables may be suspended fromwellheads or supports positioned near an interface between an overburdenand an oil shale formation without the need for support membersextending into the oil shale formation along with the insulatedconductors.

[0881] In an embodiment, a higher frequency current may be used to takeadvantage of the skin effect in certain metals. In some embodiments, a60 cycle AC current may be used in combination with conductors made ofmetals that exhibit pronounced skin effects. For example, ferromagneticmetals like iron alloys and nickel may exhibit a skin effect. The skineffect confines the current to a region close to the outer surface ofthe conductor, thereby effectively increasing the resistance of theconductor. A high resistance may be desired to decrease the operatingcurrent, minimize ohmic losses in surface cables, and minimize the costof surface facilities.

[0882] Insulated conductor 562 may be designed to operate at powerlevels of up to about 1650 watts/meter. Insulated conductor heater 562may typically operate at a power level between about 500 watts/meter andabout 1150 watts/meter when heating a formation. Insulated conductorheater 562 may be designed so that a maximum voltage level at a typicaloperating temperature does not cause substantial thermal and/orelectrical breakdown of electrical insulation 576. The insulatedconductor heater 562 may be designed so that sheath 577 does not exceeda temperature that will result in a significant reduction in corrosionresistance properties of the sheath material.

[0883] In an embodiment of insulated conductor heater 562, conductor 575may be designed to reach temperatures within a range between about 650°C. and about 870° C. The sheath 577 may be designed to reachtemperatures within a range between about 535° C. and about 760° C.Insulated conductors having other operating ranges may be formed to meetspecific operational requirements. In an embodiment of insulatedconductor heater 562, conductor 575 is designed to operate at about 760°C., sheath 577 is designed to operate at about 650° C., and theinsulated conductor heater is designed to dissipate about 820watts/meter.

[0884] Insulated conductor heater 562 may have one or more conductors575. For example, a single insulated conductor heater may have threeconductors within electrical insulation that are surrounded by a sheath.FIG. 62 depicts insulated conductor heater 562 having a single conductor575. The conductor may be made of metal. The material used to form aconductor may be, but is not limited to, nichrome, nickel, and a numberof alloys made from copper and nickel in increasing nickelconcentrations from pure copper to Alloy 30, Alloy 60, Alloy 180, andMonel. Alloys of copper and nickel may advantageously have betterelectrical resistance properties than substantially pure nickel orcopper.

[0885] In an embodiment, the conductor may be chosen to have a diameterand a resistivity at operating temperatures such that its resistance, asderived from Ohm's law, makes it electrically and structurally stablefor the chosen power dissipation per meter, the length of the heater,and/or the maximum voltage allowed to pass through the conductor. Insome embodiments, the conductor may be designed using Maxwell'sequations to make use of skin effect.

[0886] The conductor may be made of different materials along a lengthof the insulated conductor heater. For example, a first section of theconductor may be made of a material that has a significantly lowerresistance than a second section of the conductor. The first section maybe placed adjacent to a formation layer that does not need to be heatedto as high a temperature as a second formation layer that is adjacent tothe second section. The resistivity of various sections of conductor maybe adjusted by having a variable diameter and/or by having conductorsections made of different materials.

[0887] A diameter of conductor 575 may typically be between about 1.3 mmto about 10.2 mm. Smaller or larger diameters may also be used to haveconductors with desired resistivity characteristics. In an embodiment ofan insulated conductor heater, the conductor is made of Alloy 60 thathas a diameter of about 5.8 mm.

[0888] Electrical insulator 576 of insulated conductor heater 562 may bemade of a variety of materials. Pressure may be used to place electricalinsulator powder between conductor 575 and sheath 577. Low flowcharacteristics and other properties of the powder and/or the sheathsand conductors may inhibit the powder from flowing out of the sheaths.Commonly used powders may include, but are not limited to, MgO, Al₂O₃,Zirconia, BeO, different chemical variations of Spinels, andcombinations thereof. MgO may provide good thermal conductivity andelectrical insulation properties. The desired electrical insulationproperties include low leakage current and high dielectric strength. Alow leakage current decreases the possibility of thermal breakdown andthe high dielectric strength decreases the possibility of arcing acrossthe insulator. Thermal breakdown can occur if the leakage current causesa progressive rise in the temperature of the insulator leading also toarcing across the insulator. An amount of impurities 578 in theelectrical insulator powder may be tailored to provide requireddielectric strength and a low level of leakage current. Impurities 578added may be, but are not limited to, CaO, Fe₂O₃, Al₂O₃, and other metaloxides. Low porosity of the electrical insulation tends to reduceleakage current and increase dielectric strength. Low porosity may beachieved by increased packing of the MgO powder during fabrication or byfilling of the pore space in the MgO powder with other granularmaterials, for example, Al₂O₃.

[0889] Impurities 578 added to the electrical insulator powder may haveparticle sizes that are smaller than the particle sizes of the powderedelectrical insulator. The small particles may occupy pore space betweenthe larger particles of the electrical insulator so that the porosity ofthe electrical insulator is reduced. Examples of powdered electricalinsulators that may be used to form electrical insulation 576 are “H”mix manufactured by Idaho Laboratories Corporation (Idaho Falls, Id.) orStandard MgO used by Pyrotenax Cable Company (Trenton, Ontario) for hightemperature applications. In addition, other powdered electricalinsulators may be used.

[0890] Sheath 577 of insulated conductor heater 562 may be an outermetallic layer. Sheath 577 may be in contact with hot formation fluids.Sheath 577 may need to be made of a material having a high resistance tocorrosion at elevated temperatures. Alloys that may be used in a desiredoperating temperature range of the sheath include, but are not limitedto, 304 stainless steel, 310 stainless steel, Incoloy 800, and Inconel600. The thickness of the sheath has to be sufficient to last for threeto ten years in a hot and corrosive environment. A thickness of thesheath may generally vary between about 1 mm and about 2.5 mm. Forexample, a 1.3 mm thick, 310 stainless steel outer layer may be used assheath 577 to provide good chemical resistance to sulfidation corrosionin a heated zone of a formation for a period of over 3 years. Larger orsmaller sheath thicknesses may be used to meet specific applicationrequirements.

[0891] An insulated conductor heater may be tested after fabrication.The insulated conductor heater may be required to withstand 2-3 times anoperating voltage at a selected operating temperature. Also, selectedsamples of produced insulated conductor heaters may be required towithstand 1000 VAC at 760° C. for one month.

[0892] As illustrated in FIG. 63, short flexible transition conductor571 may be connected to lead-in conductor 572 using connection 569 madeduring heater installation in the field. Transition conductor 571 may bea flexible, low resistivity, stranded copper cable that is surrounded byrubber or polymer insulation. Transition conductor 571 may typically bebetween about 1.5 m and about 3 m, although longer or shorter transitionconductors may be used to accommodate particular needs. Temperatureresistant cable may be used as transition conductor 571. Transitionconductor 571 may also be connected to a short length of an insulatedconductor heater that is less resistive than a primary heating sectionof the insulated conductor heater. The less resistive portion of theinsulated conductor heater may be referred to as “cold pin” 568.

[0893] Cold pin 568 may be designed to dissipate about one-tenth toabout one-fifth of the power per unit length as is dissipated in a unitlength of the primary heating section. Cold pins may typically bebetween about 1.5 m and about 15 m, although shorter or longer lengthsmay be used to accommodate specific application needs. In an embodiment,the conductor of a cold pin section is copper with a diameter of about6.9 mm and a length of 9.1 m. The electrical insulation is the same typeof insulation used in the primary heating section. A sheath of the coldpin may be made of Inconel 600. Chloride corrosion cracking in the coldpin region may occur, so a chloride corrosion resistant metal such asInconel 600 may be used as the sheath.

[0894] As illustrated in FIG. 63, small, epoxy filled canister 573 maybe used to create a connection between transition conductor 571 and coldpin 568. Cold pins 568 may be connected to the primary heating sectionsof insulated conductor 562 heaters by “splices” 567. The length of coldpin 568 may be sufficient to significantly reduce a temperature ofinsulated conductor heater 562. The heater section of the insulatedconductor heater 562 may operate from about 530° C. to about 760° C.,splice 567 may be at a temperature from about 260° C. to about 370° C.,and the temperature at the lead-in cable connection to the cold pin maybe from about 40° C. to about 90° C. In addition to a cold pin at a topend of the insulated conductor heater, a cold pin may also be placed ata bottom end of the insulated conductor heater. The cold pin at thebottom end may in many instances make a bottom termination easier tomanufacture.

[0895] Splice material may have to withstand a temperature equal to halfof a target zone operating temperature. Density of electrical insulationin the splice should in many instances be high enough to withstand therequired temperature and the operating voltage.

[0896] Splice 567 may be required to withstand 1000 VAC at 480° C.Splice material may be high temperature splices made by IdahoLaboratories Corporation or by Pyrotenax Cable Company. A splice may bean internal type of splice or an external splice. An internal splice istypically made without welds on the sheath of the insulated conductorheater. The lack of weld on the sheath may avoid potential weak spots(mechanical and/or electrical) on the insulated cable heater. Anexternal splice is a weld made to couple sheaths of two insulatedconductor heaters together. An external splice may need to be leaktested prior to insertion of the insulated cable heater into aformation. Laser welds or orbital TIG (tungsten inert gas) welds may beused to form external splices. An additional strain relief assembly maybe placed around an external splice to improve the splice's resistanceto bending and to protect the external splice against partial or totalparting.

[0897] In certain embodiments, an insulated conductor assembly, such asthe assembly depicted in FIG. 64 and FIG. 63, may have to withstand ahigher operating voltage than normally would be used. For example, forheaters greater than about 700 m in length, voltages greater than about2000 V may be needed for generating heat with the insulated conductor,as compared to voltages of about 480 V that may be used with heatershaving lengths of less than about 225 m. In such cases, it may beadvantageous to form insulated conductor 562, cold pin 568, transitionconductor 571, and lead-in conductor 572 into a single insulatedconductor assembly. In some embodiments, cold pin 568 and canister 573may not be required as shown in FIG. 63. In such an embodiment, splice567 can be used to directly couple insulated conductor 562 to transitionconductor 571.

[0898] In a heat source embodiment, insulated conductor 562, transitionconductor 571, and lead-in conductor 572 each include insulatedconductors of varying resistance. Resistance of the conductors may bevaried, for example, by altering a type of conductor, a diameter of aconductor, and/or a length of a conductor. In an embodiment, diametersof insulated conductor 562, transition conductor 571, and lead-inconductor 572 are different. Insulated conductor 562 may have a diameterof 6 mm, transition conductor 571 may have a diameter of 7 mm, andlead-in conductor 572 may have a diameter of 8 mm. Smaller or largerdiameters may be used to accommodate site conditions (e.g., heatingrequirements or voltage requirements). Insulated conductor 562 may havea higher resistance than either transition conductor 571 or lead-inconductor 572, such that more heat is generated in the insulatedconductor. Also, transition conductor 571 may have a resistance betweena resistance of insulated conductor 562 and lead-in conductor 572.Insulated conductor 562, transition conductor 571, and lead-in conductor572 may be coupled using splice 567 and/or connection 569. Splice 567and/or connection 569 may be required to withstand relatively largeoperating voltages depending on a length of insulated conductor 562and/or lead-in conductor 572. Splice 567 and/or connection 569 mayinhibit arcing and/or voltage breakdowns within the insulated conductorassembly. Using insulated conductors for each cable within an insulatedconductor assembly may allow for higher operating voltages within theassembly.

[0899] An insulated conductor assembly may include heating sections,cold pins, splices, termination canisters and flexible transitionconductors. The insulated conductor assembly may need to be examined andelectrically tested before installation of the assembly into an openingin a formation. The assembly may need to be examined for competent weldsand to make sure that there are no holes in the sheath anywhere alongthe whole heater (including the heated section, the cold-pins, thesplices, and the termination cans). Periodic X-ray spot checking of thecommercial product may need to be made. The whole cable may be immersedin water prior to electrical testing. Electrical testing of the assemblymay need to show more than 2000 megaohms at 500 VAC at room temperatureafter water immersion. In addition, the assembly may need to beconnected to 1000 VAC and show less than about 10 microamps per meter ofresistive leakage current at room temperature. In addition, a check onleakage current at about 760° C. may need to show less than about 0.4milliamps per meter.

[0900] A number of companies manufacture insulated conductor heaters.Such manufacturers include, but are not limited to, MI CableTechnologies (Calgary, Alberta), Pyrotenax Cable Company (Trenton,Ontario), Idaho Laboratories Corporation (Idaho Falls, Id.), and Watlow(St. Louis, Mo.). As an example, an insulated conductor heater may beordered from Idaho Laboratories as cable model 355-A90-310-“H”30′/750′/30′ with Inconel 600 sheath for the cold-pins, three phase Yconfiguration and bottom jointed conductors. The specification for theheater may also include 1000 VAC, 1400° F. quality cable. The designator355 specifies the cable OD (0.355″); A90 specifies the conductormaterial; 310 specifies the heated zone sheath alloy (SS 310); “H”specifies the MgO mix; and 30′/750′/30′ specifies about a 230 m heatedzone with cold-pins top and bottom having about 9 m lengths. A similarpart number with the same specification using high temperature Standardpurity MgO cable may be ordered from Pyrotenax Cable Company.

[0901] One or more insulated conductor heaters may be placed within anopening in a formation to form a heat source or heat sources. Electricalcurrent may be passed through each insulated conductor heater in theopening to heat the formation. Alternately, electrical current may bepassed through selected insulated conductor heaters in an opening. Theunused conductors may be backup heaters. Insulated conductor heaters maybe electrically coupled to a power source in any convenient manner. Eachend of an insulated conductor heater may be coupled to lead-in cablesthat pass through a wellhead. Such a configuration typically has a 180°bend (a “hairpin” bend) or turn located near a bottom of the heatsource. An insulated conductor heater that includes a 180° bend or turnmay not require a bottom termination, but the 180° bend or turn may bean electrical and/or structural weakness in the heater. Insulatedconductor heaters may be electrically coupled together in series, inparallel, or in series and parallel combinations. In some embodiments ofheat sources, electrical current may pass into the conductor of aninsulated conductor heater and may be returned through the sheath of theinsulated conductor heater by connecting conductor 575 to sheath 577 atthe bottom of the heat source.

[0902] In the embodiment of a heat source depicted in FIG. 64, threeinsulated conductor heaters 562 are electrically coupled in a 3-phase Yconfiguration to a power supply. The power supply may provide 60 cycleAC current to the electrical conductors. No bottom connection may berequired for the insulated conductor heaters. Alternately, all threeconductors of the three phase circuit may be connected together near thebottom of a heat source opening. The connection may be made directly atends of heating sections of the insulated conductor heaters or at endsof cold pins coupled to the heating sections at the bottom of theinsulated conductor heaters. The bottom connections may be made withinsulator filled and sealed canisters or with epoxy filled canisters.The insulator may be the same composition as the insulator used as theelectrical insulation.

[0903] The three insulated conductor heaters depicted in FIG. 64 may becoupled to support member 564 using centralizers 566. Alternatively, thethree insulated conductor heaters may be strapped directly to thesupport tube using metal straps. Centralizers 566 may maintain alocation or inhibit movement of insulated conductor heaters 562 onsupport member 564. Centralizers 566 may be made of metal, ceramic, orcombinations thereof. The metal may be stainless steel or any other typeof metal able to withstand a corrosive and hot environment. In someembodiments, centralizers 566 may be bowed metal strips welded to thesupport member at distances less than about 6 m. A ceramic used incentralizer 566 may be, but is not limited to, Al₂O₃, MgO, or otherinsulator. Centralizers 566 may maintain a location of insulatedconductor heaters 562 on support member 564 such that movement ofinsulated conductor heaters is inhibited at operating temperatures ofthe insulated conductor heaters. Insulated conductor heaters 562 mayalso be somewhat flexible to withstand expansion of support member 564during heating.

[0904] Support member 564, insulated conductor heater 562, andcentralizers 566 may be placed in opening 514 in hydrocarbon layer 516.Insulated conductor heaters 562 may be coupled to bottom conductorjunction 570 using cold pin transition conductor 568. Bottom conductorjunction 570 may electrically couple each insulated conductor heater 562to each other. Bottom conductor junction 570 may include materials thatare electrically conducting and do not melt at temperatures found inopening 514. Cold pin transition conductor 568 may be an insulatedconductor heater having lower electrical resistance than insulatedconductor heater 562. As illustrated in FIG. 63, cold pin 568 may becoupled to transition conductor 571 and insulated conductor heater 562.Cold pin transition conductor 568 may provide a temperature transitionbetween transition conductor 571 and insulated conductor heater 562.

[0905] Lead-in conductor 572 may be coupled to wellhead 590 to provideelectrical power to insulated conductor heater 562. Lead-in conductor572 may be made of a relatively low electrical resistance conductor suchthat relatively little heat is generated from electrical current passingthrough lead-in conductor 572. In some embodiments, the lead-inconductor is a rubber or polymer insulated stranded copper wire. In someembodiments, the lead-in conductor is a mineral-insulated conductor witha copper core. Lead-in conductor 572 may couple to wellhead 590 atsurface 550 through a sealing flange located between overburden 540 andsurface 550. The sealing flange may inhibit fluid from escaping fromopening 514 to surface 550.

[0906] Packing material 542 may be placed between overburden casing 541and opening 514. In some embodiments, cement 544 may secure overburdencasing 541 to overburden 540. In an embodiment of a heat source,overburden casing is a 7.6 cm (3 inch) diameter carbon steel, schedule40 pipe. Packing material 542 may inhibit fluid from flowing fromopening 514 to surface 550. Cement 544 may include, for example, Class Gor Class H Portland cement mixed with silica flour for improved hightemperature performance, slag or silica flour, and/or a mixture thereof(e.g., about 1.58 grams per cubic centimeter slag/silica flour). In someheat source embodiments, cement 544 extends radially a width of fromabout 5 cm to about 25 cm. In some embodiments, cement 544 may extendradially a width of about 10 cm to about 15 cm. Cement 544 may inhibitheat transfer from conductor 564 into overburden 540.

[0907] In certain embodiments, one or more conduits may be provided tosupply additional components (e.g., nitrogen, carbon dioxide, reducingagents such as gas containing hydrogen, etc.) to formation openings, tobleed off fluids, and/or to control pressure. Formation pressures tendto be highest near heating sources. Providing pressure control equipmentin heat sources may be beneficial. In some embodiments, adding areducing agent proximate the heating source assists in providing a morefavorable pyrolysis environment (e.g., a higher hydrogen partialpressure). Since permeability and porosity tend to increase more quicklyproximate the heating source, it is often optimal to add a reducingagent proximate the heating source so that the reducing agent can moreeasily move into the formation.

[0908] Conduit 5000, depicted in FIG. 64, may be provided to add gasfrom gas source 5003, through valve 5001, and into opening 514. Opening5004 is provided in packing material 542 to allow gas to pass intoopening 514. Conduit 5000 and valve 5002 may be used at different timesto bleed off pressure and/or control pressure proximate opening 514.Conduit 5010, depicted in FIG. 66, may be provided to add gas from gassource 5013, through valve 5011, and into opening 514. An opening isprovided in cement 544 to allow gas to pass into opening 514. Conduit5010 and valve 5012 may be used at different times to bleed off pressureand/or control pressure proximate opening 514. It is to be understoodthat any of the heating sources described herein may also be equippedwith conduits to supply additional components, bleed off fluids, and/orto control pressure.

[0909] As shown in FIG. 64, support member 564 and lead-in conductor 572may be coupled to wellhead 590 at surface 550 of the formation. Surfaceconductor 545 may enclose cement 544 and couple to wellhead 590.Embodiments of surface conductor 545 may have an outer diameter of about10.16 cm to about 30.48 cm or, for example, an outer diameter of about22 cm. Embodiments of surface conductors may extend to depths ofapproximately 3 m to approximately 515 m into an opening in theformation. Alternatively, the surface conductor may extend to a depth ofapproximately 9 m into the opening. Electrical current may be suppliedfrom a power source to insulated conductor heater 562 to generate heatdue to the electrical resistance of conductor 575 as illustrated in FIG.62. As an example, a voltage of about 330 volts and a current of about266 amps are supplied to insulated conductor 562 to generate a heat ofabout 1150 watts/meter in insulated conductor heater 562. Heat generatedfrom the three insulated conductor heaters 562 may transfer (e.g., byradiation) within opening 514 to heat at least a portion of thehydrocarbon layer 516.

[0910] An appropriate configuration of an insulated conductor heater maybe determined by optimizing a material cost of the heater based on alength of heater, a power required per meter of conductor, and a desiredoperating voltage. In addition, an operating current and voltage may bechosen to optimize the cost of input electrical energy in conjunctionwith a material cost of the insulated conductor heaters. For example, asinput electrical energy increases, the cost of materials needed towithstand the higher voltage may also increase. The insulated conductorheaters may generate radiant heat of approximately 650 watts/meter ofconductor to approximately 1650 watts/meter of conductor. The insulatedconductor heater may operate at a temperature between approximately 530°C. and approximately 760° C. within a formation.

[0911] Heat generated by an insulated conductor heater may heat at leasta portion of an oil shale formation. In some embodiments, heat may betransferred to the formation substantially by radiation of the generatedheat to the formation. Some heat may be transferred by conduction orconvection of heat due to gases present in the opening. The opening maybe an uncased opening. An uncased opening eliminates cost associatedwith thermally cementing the heater to the formation, costs associatedwith a casing, and/or costs of packing a heater within an opening. Inaddition, heat transfer by radiation is typically more efficient than byconduction, so the heaters may be operated at lower temperatures in anopen wellbore. Conductive heat transfer during initial operation of aheat source may be enhanced by the addition of a gas in the opening. Thegas may be maintained at a pressure up to about 27 bars absolute. Thegas may include, but is not limited to, carbon dioxide and/or helium. Aninsulated conductor heater in an open wellbore may advantageously befree to expand or contract to accommodate thermal expansion andcontraction. An insulated conductor heater may advantageously beremovable from an open wellbore.

[0912] In an embodiment, an insulated conductor heater may be installedor removed using a spooling assembly. More than one spooling assemblymay be used to install both the insulated conductor and a support membersimultaneously. U.S. Pat. No. 4,572,299 issued to Van Egmond et al.,which is incorporated by reference as if fully set forth herein,describes spooling an electric heater into a well. Alternatively, thesupport member may be installed using a coiled tubing unit. The heatersmay be un-spooled and connected to the support as the support isinserted into the well. The electric heater and the support member maybe un-spooled from the spooling assemblies. Spacers may be coupled tothe support member and the heater along a length of the support member.Additional spooling assemblies may be used for additional electricheater elements.

[0913] In an in situ conversion process embodiment, a heater may beinstalled in a substantially horizontal wellbore. Installing a heater ina wellbore (whether vertical or horizontal) may include placing one ormore heaters (e.g., three mineral insulated conductor heaters) within aconduit. FIG. 67 depicts an embodiment of a portion of three insulatedconductor heaters 6232 placed within conduit 6234. Insulated conductorheaters 6232 may be spaced within conduit 6234 using spacers 6236 tolocate the insulated conductor heater within the conduit.

[0914] The conduit may be reeled onto a spool. The spool may be placedon a transporting platform such as a truck bed or other platform thatcan be transported to a site of a wellbore. The conduit may be unreeledfrom the spool at the wellbore and inserted into the wellbore to installthe heater within the wellbore. A welded cap may be placed at an end ofthe coiled conduit. The welded cap may be placed at an end of theconduit that enters the wellbore first. The conduit may allow easyinstallation of the heater into the wellbore. The conduit may alsoprovide support for the heater.

[0915] In some heat source embodiments, coiled tubing installation maybe used to install one or more wellbore elements placed in openings in aformation for an in situ conversion process. For example, a coiledconduit may be used to install other types of wells in a formation. Theother types of wells may be, but are not limited to, monitor wells,freeze wells or portions of freeze wells, dewatering wells or portionsof dewatering wells, outer casings, injection wells or portions ofinjection wells, production wells or portions of production wells, andheat sources or portions of heat sources. Installing one or morewellbore elements using a coiled conduit installation process may beless expensive and faster than using other installation processes.

[0916] Coiled tubing installation may reduce a number of welded and/orthreaded connections in a length of casing. Welds and/or threadedconnections in coiled tubing may be pre-tested for integrity (e.g., byhydraulic pressure testing). Coiled tubing is available from QualityTubing, Inc. (Houston, Tex.), Precision Tubing (Houston, Tex.), andother manufacturers. Coiled tubing may be available in many sizes anddifferent materials. Sizes of coiled tubing may range from about 2.5 cm(1 inch) to about 15 cm (6 inches). Coiled tubing may be available in avariety of different metals, including carbon steel. Coiled tubing maybe spooled on a large diameter reel. The reel may be carried on a coiledtubing unit. Suitable coiled tubing units are available from Halliburton(Duncan, Okla.), Fleet Cementers, Inc. (Cisco, Tex.), and Coiled TubingSolutions, Inc. (Eastland, Tex.). Coiled tubing may be unwound from thereel, passed through a straightener, and inserted into a wellbore. Awellcap may be attached (e.g., welded) to an end of the coiled tubingbefore inserting the coiling tubing into a well. After insertion, thecoiled tubing may be cut from the coiled tubing on the reel.

[0917] In some embodiments, coiled tubing may be inserted into apreviously cased opening, e.g., if a well is to be used later as aheater well, production well, or monitoring well. Alternately, coiledtubing installed within a wellbore can later be perforated (e.g., with aperforation gun) and used as a production conduit.

[0918] Embodiments of heat sources, production wells, and/or freezewells may be installed in a formation using coiled tubing installation.Some embodiments of heat sources, production wells, and freeze wellsinclude an element placed within an outer casing. For example, aconductor-in-conduit heater may include an outer conduit with an innerconduit placed in the outer conduit. A production well may include aheater element or heater elements placed within a casing to inhibitcondensation and refluxing of vapor phase production fluids. A freezewell may include a refrigerant input line placed within a casing, or arefrigeration inlet and outlet line. Spacers may be spaced along alength of an element, or elements, positioned within a casing to inhibitthe element, or elements, from contacting walls of the casing.

[0919] In some embodiments of heat sources, production wells, and freezewells, casings may be installed using coiled tube installation. Elementsmay be placed within the casing after the casing is placed in theformation for heat sources or wells that include elements within thecasings. In some embodiments, sections of casings may be threaded and/orwelded and inserted into a wellbore using a drilling rig or workoverrig. In some embodiments of heat sources, production wells, and freezewells, elements may be placed within the casing before the casing iswound onto a reel.

[0920] Some wells may have sealed casings that inhibit fluid flow fromthe formation into the casing. Sealed casings also inhibit fluid flowfrom the casing into the formation. Some casings may be perforated,screened or have other types of openings that allow fluid to pass intothe casing from the formation, or fluid from the casing to pass into theformation. In some embodiments, portions of wells are open wellboresthat do not include casings.

[0921] In an embodiment, the support member may be installed usingstandard oil field operations and welding different sections of support.Welding may be done by using orbital welding. For example, a firstsection of the support member may be disposed into the well. A secondsection (e.g., of substantially similar length) may be coupled to thefirst section in ma the well. The second section may be coupled bywelding the second section to the first section. An orbital welderdisposed at the wellhead may weld the second section to the firstsection. This process may be repeated with subsequent sections coupledto previous sections until a support of desired length is within thewell.

[0922]FIG. 65 illustrates a cross-sectional view of one embodiment of awellhead coupled to overburden casing 541. Flange 590 c may be coupledto, or may be a part of, wellhead 590. Flange 590 c may be formed ofcarbon steel, stainless steel, or any other material. Flange 590 c maybe sealed with o-ring 590 f, or any other sealing mechanism. Supportmember 564 may be coupled to flange 590 c. Support member 564 maysupport one or more insulated conductor heaters. In an embodiment,support member 564 is sealed in flange 590 c by welds 590 h.

[0923] Power conductor 590 a may be coupled to a lead-in cable and/or aninsulated conductor heater. Power conductor 590 a may provide electricalenergy to the insulated conductor heater. Power conductor 590 a may besealed in sealing flange 590 d. Sealing flange 590 d may be sealed bycompression seals or o-rings 590 e. Power conductor 590 a may be coupledto support member 564 with band 590 i. Band 590 i may include a rigidand corrosion resistant material such as stainless steel. Wellhead 590may be sealed with weld 590 h such that fluids are inhibited fromescaping the formation through wellhead 590. Lift bolt 590 j may liftwellhead 590 and support member 564.

[0924] Thermocouple 590 g may be provided through flange 590 c.Thermocouple 590 g may measure a temperature on or proximate supportmember 564 within the heated portion of the well. Compression fittings590 k may serve to seal power cable 590 a. Compression fittings 590 lmay serve to seal thermocouple 590 g. The compression fittings mayinhibit fluids from escaping the formation. Wellhead 590 may alsoinclude a pressure control valve. The pressure control valve may controlpressure within an opening in which support member 564 is disposed.

[0925] In a heat source embodiment, a control system may controlelectrical power supplied to an insulated conductor heater. Powersupplied to the insulated conductor heater may be controlled with anyappropriate type of controller. For alternating current, the controllermay be, but is not limited to, a tapped transformer or a zero crossoverelectric heater firing SCR (silicon controlled rectifier) controller.Zero crossover electric heater firing control may be achieved byallowing full supply voltage to the insulated conductor heater to passthrough the insulated conductor heater for a specific number of cycles,starting at the “crossover,” where an instantaneous voltage may be zero,continuing for a specific number of complete cycles, and discontinuingwhen the instantaneous voltage again crosses zero. A specific number ofcycles may be blocked, allowing control of the heat output by theinsulated conductor heater. For example, the control system may bearranged to block fifteen and/or twenty cycles out of each sixty cyclesthat are supplied by a standard 60 Hz alternating current power supply.Zero crossover firing control may be advantageously used with materialshaving low temperature coefficient materials. Zero crossover firingcontrol may inhibit current spikes from occurring in an insulatedconductor heater.

[0926]FIG. 66 illustrates an embodiment of a conductor-in-conduit heaterthat may heat an oil shale formation. Conductor 580 may be disposed inconduit 582. Conductor 580 may be a rod or conduit of electricallyconductive material. Low resistance sections 584 may be present at bothends of conductor 580 to generate less heating in these sections. Lowresistance section 584 may be formed by having a greater cross-sectionalarea of conductor 580 in that section, or the sections may be made ofmaterial having less resistance. In certain embodiments, low resistancesection 584 includes a low resistance conductor coupled to conductor580. In some heat source embodiments, conductors 580 may be 316, 304, or310 stainless steel rods with diameters of approximately 2.8 cm. In someheat source embodiments, conductors are 316, 304, or 310 stainless steelpipes with diameters of approximately 2.5 cm. Larger or smallerdiameters of rods or pipes may be used to achieve desired heating of aformation. The diameter and/or wall thickness of conductor 580 may bevaried along a length of the conductor to establish different heatingrates at various portions of the conductor.

[0927] Conduit 582 may be made of an electrically conductive material.For example, conduit 582 may be a 7.6 cm, schedule 40 pipe made of 316,304, or 310 stainless steel. Conduit 582 may be disposed in opening 514in hydrocarbon layer 516. Opening 514 has a diameter able to accommodateconduit 582. A diameter of the opening may be from about 10 cm to about13 cm. Larger or smaller diameter openings may be used to accommodateparticular conduits or designs.

[0928] Conductor 580 may be centered in conduit 582 by centralizer 581.Centralizer 581 may electrically isolate conductor 580 from conduit 582.Centralizer 581 may inhibit movement and properly locate conductor 580within conduit 582. Centralizer 581 may be made of a ceramic material ora combination of ceramic and metallic materials. Centralizers 581 mayinhibit deformation of conductor 580 in conduit 582. Centralizer 581 maybe spaced at intervals between approximately 0.5 m and approximately 3 malong conductor 580. FIGS. 68, 69, and 70 depict embodiments ofcentralizers 581.

[0929] A second low resistance section 584 of conductor 580 may coupleconductor 580 to wellhead 690, as depicted in FIG. 66. Electricalcurrent may be applied to conductor 580 from power cable 585 through lowresistance section 584 of conductor 580. Electrical current may passfrom conductor 580 through sliding connector 583 to conduit 582. Conduit582 may be electrically insulated from overburden casing 541 and fromwellhead 690 to return electrical current to power cable 585. Heat maybe generated in conductor 580 and conduit 582. The generated heat mayradiate within conduit 582 and opening 514 to heat at least a portion ofhydrocarbon layer 516. As an example, a voltage of about 330 volts and acurrent of about 795 amps may be supplied to conductor 580 and conduit582 in a 229 m (750 ft) heated section to generate about 1150watts/meter of conductor 580 and conduit 582.

[0930] Overburden conduit 541 may be disposed in overburden 540.Overburden conduit 541 may, in some embodiments, be surrounded bymaterials that inhibit heating of overburden 540. Low resistance section584 of conductor 580 may be placed in overburden conduit 541. Lowresistance section 584 of conductor 580 may be made of, for example,carbon steel. Low resistance section 584 may have a diameter betweenabout 2 cm to about 5 cm or, for example, a diameter of about 4 cm. Lowresistance section 584 of conductor 580 may be centralized withinoverburden conduit 541 using centralizers 581. Centralizers 581 may bespaced at intervals of approximately 6 m to approximately 12 m or, forexample, approximately 9 m along low resistance section 584 of conductor580. In a heat source embodiment, low resistance section 584 ofconductor 580 is coupled to conductor 580 by a weld or welds. In otherheat source embodiments, low resistance sections may be threaded,threaded and welded, or otherwise coupled to the conductor. Lowresistance section 584 may generate little and/or no heat in overburdenconduit 541. Packing material 542 may be placed between overburdencasing 541 and opening 514. Packing material 542 may inhibit fluid fromflowing from opening 514 to surface 550.

[0931] In a heat source embodiment, overburden conduit is a 7.6 cmschedule 40 carbon steel pipe. In some embodiments, the overburdenconduit may be cemented in the overburden. Cement 544 may be slag orsilica flour or a mixture thereof (e.g., about 1.58 grams per cubiccentimeter slag/silica flour). Cement 544 may extend radially a width ofabout 5 cm to about 25 cm. Cement 544 may also be made of materialdesigned to inhibit flow of heat into overburden 540. In other heatsource embodiments, overburden may not be cemented into the formation.Having an uncemented overburden casing may facilitate removal of conduit582 if the need for removal should arise.

[0932] Surface conductor 545 may couple to wellhead 690. Surfaceconductor 545 may have a diameter of about 10 cm to about 30 cm or, incertain embodiments, a diameter of about 22 cm. Electrically insulatingsealing flanges may mechanically couple low resistance section 584 ofconductor 580 to wellhead 690 and to electrically couple low resistancesection 584 to power cable 585. The electrically insulating sealingflanges may couple power cable 585 to wellhead 690. For example, lead-inconductor 585 may include a copper cable, wire, or other elongatedmember. Lead-in conductor 585 may include any material having asubstantially low resistance. The lead-in conductor may be clamped tothe bottom of the low resistance conductor to make electrical contact.

[0933] In an embodiment, heat may be generated in or by conduit 582.About 10% to about 30%, or, for example, about 20%, of the total heatgenerated by the heater may be generated in or by conduit 582. Bothconductor 580 and conduit 582 may be made of stainless steel. Dimensionsof conductor 580 and conduit 582 may be chosen such that the conductorwill dissipate heat in a range from approximately 650 watts per meter to1650 watts per meter. A temperature in conduit 582 may be approximately480° C. to approximately 815° C., and a temperature in conductor 580 maybe approximately 500° C. to 840° C. Substantially uniform heating of anoil shale formation may be provided along a length of conduit 582greater than about 300 m or, even greater than about 600 m.

[0934]FIG. 71 depicts a cross-sectional representation of an embodimentof a removable conductor-in-conduit heat source. Conduit 582 may beplaced in opening 514 through overburden 540 such that a gap remainsbetween the conduit and overburden casing 541. Fluids may be removedfrom opening 514 through the gap between conduit 582 and overburdencasing 541. Fluids may be removed from the gap through conduit 5010.Conduit 582 and components of the heat source included within theconduit that are coupled to wellhead 690 may be removed from opening 514as a single unit. The heat source may be removed as a single unit to berepaired, replaced, and/or used in another portion of the formation.

[0935] In certain embodiments, portions of a conductor-in-conduit heatsource may be moved or removed to adjust a portion of the formation thatis heated by the heat source. For example, in a horizontal well theconductor-in-conduit heat source may be initially almost as long as theopening in the formation. As products are produced from the formation,the conductor-in-conduit heat source may be moved so that it is placedat location further from the end of the opening in the formation. Heatmay be applied to a different portion of the formation by adjusting thelocation of the heat source. In certain embodiments, an end of theheater may be coupled to a sealing mechanism (e.g., a packing mechanism,or a plugging mechanism) to seal off perforations in a liner or casing.The sealing mechanism may inhibit undesired fluid production fromportions of the heat source wellbore from which the conductor-in-conduitheat source has been removed.

[0936] As depicted in FIG. 72, sliding connector 583 may be coupled nearan end of conductor 580. Sliding connector 583 may be positioned near abottom end of conduit 582. Sliding connector 583 may electrically coupleconductor 580 to conduit 582. Sliding connector 583 may move during useto accommodate thermal expansion and/or contraction of conductor 580 andconduit 582 relative to each other. In some embodiments, slidingconnector 583 may be attached to low resistance section 584 of conductor580. The lower resistance of section 584 may allow the sliding connectorto be at a temperature that does not exceed about 90° C. Maintainingsliding connector 583 at a relatively low temperature may inhibitcorrosion of the sliding connector and promote good contact between thesliding connector and conduit 582.

[0937] Sliding connector 583 may include scraper 593. Scraper 593 mayabut an inner surface of conduit 582 at point 595. Scraper 593 mayinclude any metal or electrically conducting material (e.g., steel orstainless steel). Centralizer 591 may couple to conductor 580. In someembodiments, sliding connector 583 may be positioned on low resistancesection 584 of conductor 580. Centralizer 591 may include anyelectrically conducting material (e.g., a metal or metal alloy). Springbow 592 may couple scraper 593 to centralizer 591. Spring bow 592 mayinclude any metal or electrically conducting material (e.g.,copper-beryllium alloy). In some embodiments, centralizer 591, springbow 592, and/or scraper 593 are welded together.

[0938] More than one sliding connector 583 may be used for redundancyand to reduce the current through each scraper 593. In addition, athickness of conduit 582 may be increased for a length adjacent tosliding connector 583 to reduce heat generated in that portion ofconduit. The length of conduit 582 with increased thickness may be, forexample, approximately 6 m.

[0939]FIG. 73 illustrates an embodiment of a wellhead. Wellhead 690 maybe coupled to electrical junction box 690 a by flange 690 n or any othersuitable mechanical device. Electrical junction box 690 a may controlpower (current and voltage) supplied to an electric heater. Power source690 t may be included in electrical junction box 690 a. In a heat sourceembodiment, the electric heater is a conductor-in-conduit heater. Flange690 n may include stainless steel or any other suitable sealingmaterial. Conductor 690 b may electrically couple conduit 582 to powersource 690 t. In some embodiments, power source 690 t may be locatedoutside wellhead 690 and the power source is coupled to the wellheadwith power cable 585, as shown in FIG. 66. Low resistance section 584may be coupled to power source 690 t. Compression seal 690 c may sealconductor 690 b at an inner surface of electrical junction box 690 a.

[0940] Flange 690 n may be sealed with metal o-ring 690 d. Conduit 690 fmay couple flange 690 n to flange 690 m. Flange 690 m may couple to anoverburden casing. Flange 690 m may be sealed with o-ring 690 g (e.g.,metal o-ring or steel o-ring). Low resistance section 584 of theconductor may couple to electrical junction box 690 a. Low resistancesection 584 may be passed through flange 690 n. Low resistance section584 may be sealed in flange 690 n with o-ring assembly 690 p. Assemblies690 p are designed to insulate low resistance section 584 from flange690 n and flange 690 m. Compression seal 690 c may be designed toelectrically insulate conductor 690 b from flange 690 n and junction box690 a. Centralizer 581 may couple to low resistance section 584.Thermocouples 690 i may be coupled to thermocouple flange 690 q withconnectors 690 h and wire 690 j. Thermocouples 690 i may be enclosed inan electrically insulated sheath (e.g., a metal sheath). Thermocouples690 i may be sealed in thermocouple flange 690 q with compression seals690 k. Thermocouples 690 i may be used to monitor temperatures in theheated portion downhole. In some embodiments, fluids (e.g., vapors) maybe removed through wellhead 690. For example, fluids from outsideconduit 582 may be removed through flange 690 r or fluids within theconduit may be removed through flange 690 s.

[0941]FIG. 74 illustrates an embodiment of a conductor-in-conduit heaterplaced substantially horizontally within hydrocarbon layer 516. Heatedsection 6011 may be placed substantially horizontally within hydrocarbonlayer 516. Heater casing 6014 may be placed within hydrocarbon layer516. Heater casing 6014 may be formed of a corrosion resistant,relatively rigid material (e.g., 304 stainless steel). Heater casing6014 may be coupled to overburden casing 541. Overburden casing 541 mayinclude materials such as carbon steel. In an embodiment, overburdencasing 541 and heater casing 6014 have a diameter of about 15 cm.Expansion mechanism 6012 may be placed at an end of heater casing 6014to accommodate thermal expansion of the conduit during heating and/orcooling.

[0942] To install heater casing 6014 substantially horizontally withinhydrocarbon layer 516, overburden casing 541 may bend from a verticaldirection in overburden 540 into a horizontal direction withinhydrocarbon layer 516. A curved wellbore may be formed during drillingof the wellbore in the formation. Heater casing 6014 and overburdencasing 541 may be installed in the curved wellbore. A radius ofcurvature of the curved wellbore may be determined by properties ofdrilling in the overburden and the formation. For example, the radius ofcurvature may be about 200 m from point 6015 to point 6016.

[0943] Conduit 582 may be placed within heater casing 6014. In someembodiments, conduit 582 may be made of a corrosion resistant metal(e.g., 304 stainless steel). Conduit may be heated to a hightemperature. Conduit 582 may also be exposed to hot formation fluids.Conduit 582 may be treated to have a high emissivity. Conduit 582 mayhave upper section 6002. In some embodiments, upper section 6002 may bemade of a less corrosion resistant metal than other portions of conduit582 (e.g., carbon steel). A large portion of upper section 6002 may bepositioned in overburden 540 of the formation. Upper section 6002 maynot be exposed to temperatures as high as the temperatures of conduit582. In an embodiment, conduit 582 and upper section 6002 have adiameter of about 7.6 cm.

[0944] Conductor 580 may be placed in conduit 582. A portion of theconduit placed adjacent to conduit may be made of a metal that hasdesired electrical properties, emissivity, creep resistance andcorrosion resistance at high temperatures. Conductor may include, but isnot limited to, 310 stainless steel, 304 stainless steel, 316 stainlesssteel, 347 stainless steel, and/or other steel or non-steel alloys.Conductor 580 may have a diameter of about 3 cm, however, a diameter ofconductor 580 may vary depending on, but not limited to, heatingrequirements and power requirements. Conductor 580 may be located inconduit 582 using one or more centralizers 581. Centralizers 581 may beceramic or a combination of metal and ceramic. Centralizers 581 mayinhibit conductor from contacting conduit 582. In some embodiments,centralizers 581 may be coupled to conductor 580. In other embodiments,centralizers 581 may be coupled to conduit 582. Conductor 580 may beelectrically coupled to conduit 582 using sliding connector 583.

[0945] Conductor 580 may be coupled to transition conductor 6010.Transition conductor 6010 may be used as an electrical transitionbetween lead-in conductor 6004 and conductor 580. In an embodiment,transition conductor 6010 may be carbon steel. Transition conductor 6010may be coupled to lead-in conductor 6004 with electrical connector 6008.FIG. 75 illustrates an enlarged view of an embodiment of a junction oftransition conductor 6010, electrical connector 6008, insulator 6006,and lead-in conductor 6004. Lead-in conductor 6004 may include one ormore conductors (e.g., three conductors). In certain embodiments, theone or more conductors may be insulated copper conductors (e.g.,rubber-insulated copper cable). In some embodiments, the one or moreconductors may be insulated or un-insulated stranded copper cable. Asshown in FIG. 75, insulator 6006 may be placed inside lead-in conductor6004. Insulator 6006 may include electrically insulating materials suchas fiberglass. Insulator 6006 may couple electrical connector 6008 toheater support 6000. In an embodiment, electrical current may flow froma power supply through lead-in conductor 6004, through transitionconductor 6010, into conductor 580, and return through conduit 582 andupper section 6002.

[0946] Referring to FIG. 74, heater support 6000 may include a supportthat is used to install heated section 6011 in hydrocarbon layer 516.For example, heater support 6000 may be a sucker rod that is insertedthrough overburden 540 from a ground surface. The sucker rod may includeone or more portions that can be coupled to each other at the surface asthe rod is inserted into the formation. In some embodiments, heatersupport 6000 is a single piece assembled in an assembly facility.Inserting heater support 6000 into the formation may push heated section6011 into the formation.

[0947] Overburden casing 541 may be supported within overburden 540using reinforcing material 544. Reinforcing material may include cement(e.g., Portland cement). Surface conductor 545 may enclose reinforcingmaterial 544 and overburden casing 541 in a portion of overburden 540proximate the ground surface. Surface conductor 545 may include asurface casing.

[0948]FIG. 76 illustrates a schematic of an alternate embodiment of aconductor-in-conduit heater placed substantially horizontally within aformation. In an embodiment, heater support 6000 may be a low resistanceconductor (e.g., low resistance section 584 as shown in FIG. 66). Heatersupport 6000 may include carbon steel or other electrically-conductingmaterials. Heater support 6000 may be electrically coupled to transitionconductor 6010 and conductor 580.

[0949] In some embodiments, a heat source may be placed within anuncased wellbore in an oil shale formation. FIG. 78 illustrates aschematic of an embodiment of a conductor-in-conduit heater placedsubstantially horizontally within an uncased wellbore in a formation.Heated section 6011 may be placed within opening 514 in hydrocarbonlayer 516. In certain embodiments, heater support 6000 may be a lowresistance conductor (e.g., low resistance section 584 as shown in FIG.66). Heater support 6000 may be electrically coupled to transitionconductor 6010 and conductor 580. FIG. 77 depicts an alternateembodiment of the conductor-in-conduit heater shown in FIG. 78. Incertain embodiments, perforated casing 9636 may be placed in opening 514as shown in FIG. 77. In some embodiments, centralizers 581 may be usedto support perforated casing 9636 within opening 514.

[0950] In certain heat source embodiments, a cladding section may becoupled to heater support 6000 and/or upper section 6002. FIG. 79depicts an embodiment of cladding section 9200 coupled to heater support6000. Cladding may also be coupled to an upper section of conduit 582.Cladding section 9200 may reduce the electrical resistance of heatersupport 6000 and/or the upper section of conduit 582. In an embodiment,cladding section 9200 is copper tubing coupled to the heater support andthe conduit.

[0951] In other heat source embodiments, heated section 6011, as shownin FIGS. 74, 76, and 78, may be placed in a wellbore with an orientationother than substantially horizontally in hydrocarbon layer 516. Forexample, heated section 6011 may be placed in hydrocarbon layer 516 atan angle of about 45° or substantially vertically in the formation. Inaddition, elements of the heat source placed in overburden 540 (e.g.,heater support 6000, overburden casing 541, upper section 6002, etc.)may have an orientation other than substantially vertical within theoverburden.

[0952] In certain heat source embodiments, the heat source may beremovably installed in a formation. Heater support 6000 may be used toinstall and/or remove the heat source, including heated section 6011,from the formation. The heat source may be removed to repair, replace,and/or use the heat source in a different wellbore. The heat source maybe reused in the same formation or in a different formation. In someembodiments, a heat source or a portion of a heat source may be spooledon coiled tubing rig and moved to another well location.

[0953] In some embodiments for heating an oil shale formation, more thanone heater may be installed in a wellbore or heater well. Having morethan one heater in a wellbore or heat source may provide the ability toheat a selected portion or portions of a formation at a different ratethan other portions of the formation. Having more than one heater in awellbore or heat source may provide a backup heat source in the wellboreor heat source should one or more of the heaters fail. Having more thanone heater may allow a uniform temperature profile to be establishedalong a desired portion of the wellbore. Having more than one heater mayallow for rapid heating of a hydrocarbon layer or layers to a pyrolysistemperature from ambient temperature. The more than one heater mayinclude similar types of heaters or may include different types ofheaters. For example, the more than one heater may be a naturaldistributed combustor heater, an insulated conductor heater, aconductor-in-conduit heater, an elongated member heater, a downholecombustor (e.g., a downhole flameless combustor or a downholecombustor), etc.

[0954] In an in situ conversion process embodiment, a first heater in awellbore may be used to selectively heat a first portion of a formationand a second heater may be used to selectively heat a second portion ofthe formation. The first heater and the second heater may beindependently controlled. For example, heat provided by a first heatercan be controlled separately from heat provided by a second heater. Asanother example, electrical power supplied to a first electric heatermay be controlled independently of electrical power supplied to a secondelectric heater. The first portion and the second portion may be locatedat different heights or levels within a wellbore, either vertically oralong a face of the wellbore. The first portion and the second portionmay be separated by a third, or separate, portion of a formation. Thethird portion may contain hydrocarbons or may be a non-hydrocarboncontaining portion of the formation. For example, the third portion mayinclude rock or similar non-hydrocarbon containing materials. The thirdportion may be heated or unheated. In some embodiments, heat used toheat the first and second portions may be used to heat the thirdportion. Heat provided to the first and second portions maysubstantially uniformly heat the first, second, and third portions.

[0955]FIG. 68 illustrates a perspective view of an embodiment of acentralizer in conduit 582. Electrical insulator 581 a may be disposedon conductor 580. Insulator 581 a may be made of aluminum oxide or otherelectrically insulating material that has a high working temperaturelimit. Neck portion 581 j may be a bushing which has an inside diameterthat allows conductor 580 to pass through the bushing. Neck portion 581j may include electrically-insulative materials such as metal oxides andceramics (e.g., aluminum oxide). Insulator 581 a and neck portion 581 jmay be obtainable from manufacturers such as CoorsTek (Golden, Colo.) orNorton Ceramics (United Kingdom). In an embodiment, insulator 581 aand/or neck portion 581 j are made from 99% or greater purity machinablealuminum oxide. In certain embodiments, ceramic portions of a heatsource may be surface glazed. Surface glazing ceramic may seal theceramic from contamination from dirt and/or moisture. High temperaturesurface glazing of ceramics may be done by companies such as NGK-LockeInc. (Baltimore, Md.) or Johannes Gebhart (Germany).

[0956] A location of insulator 581 a on conductor 580 may be maintainedby disc 581 d. Disc 581 d may be welded to conductor 580. Spring bow 581c may be coupled to insulator 581 a by disc 581 b. Spring bow 581 c anddisc 581 b may be made of metals such as 310 stainless steel and/or anyother thermally conducting material that may be used at relatively hightemperatures. Spring bow 581 c may reduce the stress on ceramic portionsof the centralizer during installation or removal of the heater, and/orduring use of the heater. Reducing the stress on ceramic portions of thecentralizer during installation or removal may increase an operationallifetime of the heater. In some heat source embodiments, centralizer 581may have an opening that fits over an end of conductor. In otherembodiments, centralizer 581 may be assembled from two or more piecesaround a portion of conductor 580. The pieces may be coupled toconductor 580 by fastening device 581 e. Fastening device 581 e may bemade of any material that can be used at relatively high temperatures(e.g., steel).

[0957]FIG. 69 depicts a representation of an embodiment of centralizer581 disposed on conductor 580. Discs 581 d may maintain positions ofcentralizer 581 relative to conductor 580. Discs 581 d may be metaldiscs welded to conductor 580. Discs 581 d may be tack-welded toconductor 580. FIG. 70 depicts a top view representation of acentralizer embodiment. Centralizer 581 may be made of any suitableelectrically insulating material able to withstand high voltage at hightemperatures. Examples of such materials include, but are not limitedto, aluminum oxide and/or Macor. Centralizer 581 may electricallyinsulate conductor 580 from conduit 582.

[0958]FIG. 80 illustrates a cross-sectional representation of anembodiment of a centralizer placed on a conductor. FIG. 81 depicts aportion of an embodiment of a conductor-in-conduit heat source with acutout view showing a centralizer on the conductor. Centralizer 581 maybe used in a conductor-in-conduit heat source. Centralizer 581 may beused to maintain a location of conductor 580 within conduit 582.Centralizer 581 may include electrically-insulating materials such asceramics (e.g., alumina and zirconia). As shown in FIG. 80, centralizer581 may have at least one recess 581 i. Recess 581 i may be, forexample, an indentation or notch in centralizer 581 or a recess left bya portion removed from the centralizer. A cross-sectional shape ofrecess 581 i may be a rectangular shape or any other geometrical shape.In certain embodiments, recess 581 i has a shape that allows protrusion581 g to reside within the recess. Recess 581 i may be formed such thatthe recess will be placed at a junction of centralizer 581 and conductor580. In one embodiment, recess 581 i is formed at a bottom ofcentralizer 581.

[0959] At least one protrusion 581 g may be formed on conductor 580.Protrusion 581 g may be welded to conductor 580. In some embodiments,protrusion 581 g is a weld bead formed on conductor 580. Protrusion 581g may include electrically-conductive materials such as steel (e.g.,stainless steel). In certain embodiments, protrusion 581 g may includeone or more protrusions formed around the circumference of conductor580. Protrusion 581 g may be used to maintain a location of centralizer581 on conductor 580. For example, protrusion 581 g may inhibit downwardmovement of centralizer 581 along conductor 580. In some embodiments, atleast one additional recess 581 i and at least one additional protrusion581 g may be placed at a top of centralizer 581 to inhibit upwardmovement of the centralizer along conduit 580.

[0960] In an embodiment, electrically-insulating material 581 h isplaced over protrusion 581 g and recess 581 i. Electrically-insulatingmaterial 581 h may cover recess 581 i such that protrusion 581 g isenclosed within the recess and the electrically-insulating material. Insome embodiments, electrically-insulating material 581 h may partiallycover recess 581 i. Protrusion 581 g may be enclosed so that carbondeposition (i.e., coking) on protrusion 581 g during use is inhibited.Carbon may form electrically-conducting paths during use of conductor580 and conduit 582 to heat a formation. Electrically-insulatingmaterial 581 h may include materials such as, but not limited to, metaloxides and/or ceramics (e.g., alumina or zirconia). In some embodiments,electrically-insulating material 581 h is a thermally conductingmaterial. A thermal plasma spray process may be used to placeelectrically-insulating material 581 h over protrusion 581 g and recess581 i. The thermal plasma process may spray coat electrically-insulatingmaterial 581 h on protrusion 581 g and/or centralizer 581.

[0961] In an embodiment, centralizer 581 with recess 581 i, protrusion581 g, and electrically-insulating material 581 h are placed onconductor 580 within conduit 582 during installation of theconductor-in-conduit heat source in an opening in a formation. Inanother embodiment, centralizer 581 with recess 581 i, protrusion 581 g,and electrically-insulating material 581 h are placed on conductor 580within conduit 582 during assembling of the conductor-in-conduit heatsource. For example, an assembling process may include formingprotrusion 581 g on conductor 580, placing centralizer 581 with recess581 i on conductor 580, covering the protrusion and the recess withelectrically-insulating material 581 h, and placing the conductor withinconduit 582.

[0962]FIG. 82 depicts an alternate embodiment of centralizer 581. Neckportion 581 j may be coupled to centralizer 581. In certain embodiments,neck portion 581 j is an extended portion of centralizer 581. Protrusion581 g may be placed on conductor 580 to maintain a location ofcentralizer 581 and neck portion 581 j on the conductor. Neck portion581 j may be a bushing which has an inside diameter that allowsconductor 580 to pass through the bushing. Neck portion 581 j mayinclude electrically-insulative materials such as metal oxides andceramics (e.g., aluminum oxide). For example, neck portion 581 j may bea commercially available bushing from manufacturers such as BorgesTechnical Ceramics (Pennsburg, Pa.). In one embodiment, as shown in FIG.82, a first neck portion 581 j is coupled to an upper portion ofcentralizer 581 and a second neck portion 581 j is coupled to a lowerportion of centralizer 581.

[0963] Neck portion 581 j may extend between about 1 cm and about 5 cmfrom centralizer 581. In an embodiment, neck portion 581 j extends about2-3 cm from centralizer 581. Neck portion 581 j may extend a selecteddistance from centralizer 581 such that arcing (e.g., surface arcing) isinhibited. Neck portion 581 j may increase a path length for arcingbetween conductor 580 and conduit 582. A path for arcing betweenconductor 580 and conduit 582 may be formed by carbon deposition oncentralizer 581 and/or neck portion 581 j. Increasing the path lengthfor arcing between conductor 580 and conduit 582 may reduce thelikelihood of arcing between the conductor and the conduit. Anotheradvantage of increasing the path length for arcing between conductor 580and conduit 582 may be an increase in a maximum operating voltage of theconductor.

[0964] In an embodiment, neck portion 581 j also includes one or moregrooves 581 k. One or more grooves 581 k may further increase the pathlength for arcing between conductor 580 and conduit 582. In certainembodiments, conductor 580 and conduit 582 may be oriented substantiallyvertically within a formation. In such an embodiment, one or moregrooves 581 k may also inhibit deposition of conducting particles (e.g.,carbon particles or corrosion scale) along the length of neck portion581 j. Conducting particles may fall by gravity along a length ofconductor 580. One or more grooves 581 k may be oriented such thatfalling particles do not deposit into the one or more grooves.Inhibiting the deposition of conducting particles on neck portion 581 jmay inhibit formation of an arcing path between conductor 580 andconduit 582. In some embodiments, diameters of each of one or moregrooves 581 k may be varied. Varying the diameters of the grooves mayfurther inhibit the likelihood of arcing between conductor 580 andconduit 582.

[0965]FIG. 83 depicts an embodiment of centralizer 581. Centralizer 581may include two or more portions held together by fastening device 581e. Fastening device 581 e may be a clamp, bolt, snap-lock, or screw.FIGS. 84 and 85 depict top views of embodiments of centralizer 581placed on conduit 580. Centralizer 581 may include two portions. The twoportions may be coupled together to form a centralizer in a “clam shell”configuration. The two portions may have notches and recesses that areshaped to fit together as shown in either of FIGS. 84 and 85. In someembodiments, the two portions may have notches and recesses that aretapered so that the two portions tightly couple together. The twoportions may be slid together lengthwise along the notches and recesses.

[0966] In a heat source embodiment, an insulation layer may be placedbetween a conductor and a conduit. The insulation layer may be used toelectrically insulate the conductor from the conduit. The insulationlayer may also maintain a location of the conductor within the conduit.In some embodiments, the insulation layer may include a layer thatremains placed on and/or in the heat source after installation. Incertain embodiments, the insulation layer may be removed by heating theheat source to a selected temperature. The insulation layer may includeelectrically-insulating materials such as, but not limited to, metaloxides and/or ceramics. For example, the insulation layer may be Nextel™insulation obtainable from 3M Company (St. Paul, Minn.). An insulationlayer may also be used for installation of any other heat source (e.g.,insulated conductor heat source, natural distributed combustor, etc.).In an embodiment, the insulation layer is fastened to the conductor. Theinsulation layer may be fastened to the conductor with a hightemperature adhesive (e.g., a ceramic adhesive such as Cotronics 920alumina-based adhesive available from Cotronics Corporation (Brooklyn,N.Y.)).

[0967]FIG. 86 depicts a cross-sectional representation of an embodimentof a section of a conductor-in-conduit heat source with insulation layer9180. Insulation layer 9180 may be placed on conductor 580. Insulationlayer 9180 may be spiraled around conductor 580 as shown in FIG. 86. Inone embodiment, insulation layer 9180 is a single insulation layer woundaround the length of conductor 580. In some embodiments, insulationlayer 9180 may include one or more individual sections of insulationlayers wrapped around conductor 580. Conductor 580 may be placed inconduit 582 after insulation layer 9180 has been placed on theconductor. Insulation layer 9180 may electrically insulate conductor 580from conduit 582.

[0968] In an embodiment of a conductor-in-conduit heat source, a conduitmay be pressurized with a fluid to inhibit a large pressure differencebetween pressure in the conduit and pressure in the formation. Balancedpressure or a small pressure difference may inhibit deformation of theconduit during use. The fluid may increase conductive heat transfer fromthe conductor to the conduit. The fluid may include, but is not limitedto, a gas such as helium, nitrogen, air, or mixtures thereof. The fluidmay inhibit arcing between the conductor and the conduit. If air and/orair mixtures are used to pressurize the conduit, the air and/or airmixtures may react with materials of the conductor and the conduit toform an oxide layer on a surface of the conductor and/or an oxide layeron an inner surface of the conduit. The oxide layer may inhibit arcing.The oxide layer may make the conductor and/or the conduit more resistantto corrosion.

[0969] Reducing the amount of heat losses to an overburden of aformation may increase an efficiency of a heat source. The efficiency ofthe heat source may be determined by the energy transferred into theformation through the heat source as a fraction of the energy input intothe heat source. In other words, the efficiency of the heat source maybe a function of energy that actually heats a desired portion of theformation divided by the electrical power (or other input power)provided to the heat source. To increase the amount of energy actuallytransferred to the formation, heating losses to the overburden may bereduced. Heating losses in the overburden may be reduced for electricalheat sources by the use of relatively low resistance conductors in theoverburden that couple a power supply to the heat source. Alternatingelectrical current flowing through certain conductors (e.g., carbonsteel conductors) tends to flow along the skin of the conductors. Thisskin depth effect may increase the resistance heating at the outersurface of the conductor (i.e., the current flows through only a smallportion of the available metal) and, thus increase heating of theoverburden. Electrically conductive casings, coatings, wiring, and/orcladdings may be used to reduce the electrical resistance of a conductorused in the overburden. Reducing the electrical resistance of theconductor in the overburden may reduce electricity losses to heating theconduit in the overburden portion and thereby increase the availableelectricity for resistive heating in portions of the conductor below theoverburden.

[0970] As shown in FIG. 66, low resistance section 584 may be coupled toconductor 580. Low resistance section 584 may be placed in overburden540. Low resistance section 584 may be, for example, a carbon steelconductor. Carbon steel may be used to provide mechanical strength forthe heat source in overburden 540. In an embodiment, an electricallyconductive coating may be coated on low resistance section 584 tofurther reduce an electrical resistance of the low resistance conductor.In some embodiments, the electrically conductive coating may be coatedon low resistance section 584 during assembly of the heat source. Inother embodiments, the electrically conductive coating may be coated onlow resistance section 584 after installation of the heat source inopening 514.

[0971] In some embodiments, the electrically conductive coating may besprayed on low resistance section 584. For example, the electricallyconductive coating may be a sprayed on thermal plasma coating. Theelectrically conductive coating may include conductive materials suchas, but not limited to, aluminum or copper. The electrically conductivecoating may include other conductive materials that can be thermalplasma sprayed. In certain embodiments, the electrically conductivecoating may be coated on low resistance section 584 such that theresistance of the low resistance conductor is reduced by a factor ofgreater than about 2. In some embodiments, the resistance is lowered bya factor of greater than about 4 or about 5. The electrically conductivecoating may have a thickness of between 0.1 mm and 0.8 mm. In anembodiment, the electrically conductive coating may have a thickness ofabout 0.25 mm. The electrically conductive coating may be coated on lowresistance conductors used with other types of heat sources such as, forexample, insulated conductor heat sources, elongated member heatsources, etc.

[0972] In another embodiment, a cladding may be coupled to lowresistance section 584 to reduce the electrical resistance in overburden540. FIG. 87 depicts a cross-sectional view of a portion of claddingsection 9200 of conductor-in-conduit heater. Cladding section 9200 maybe coupled to the outer surface of low resistance section 584. Claddingsections 9200 may also be coupled to an inner surface of conduit 582. Incertain embodiments, cladding sections may be coupled to inner surfaceof low resistance section 584 and/or outer surface of conduit 582. Insome embodiments, low resistance section 584 may include one or moresections of individual low resistance sections 584 coupled together.Conduit 582 may include one or more sections of individual conduits 582coupled together.

[0973] Individual cladding sections 9200 may be coupled to eachindividual low resistance section 584 and/or conduit 582, as shown inFIG. 87. A gap may remain between each cladding section 9200. The gapmay be at a location of a coupling between low resistance sections 584and/or conduits 582. For example, the gap may be at a thread or weldjunction between low resistance sections 584 and/or conduits 582. Thegap may be less than about 4 cm in length. In certain embodiments, thegap may be less than about 5 cm in length or less than 6 cm in length.

[0974] Cladding section 9200 may be a conduit (or tubing) of relativelyelectrically conductive material. Cladding section 9200 may be a conduitthat tightly fits against a surface of low resistance section 584 and/orconduit 582. Cladding section 9200 may include non-ferromagnetic metalsthat have a relatively high electrical conductivity. For example,cladding section 9200 may include copper, aluminum, brass, bronze, orcombinations thereof. Cladding section 9200 may have a thickness betweenabout 0.2 cm and about 1 cm. In some embodiments, low resistance section584 has an outside diameter of about 2.5 cm and conduit 582 has aninside diameter of about 7.3 cm. In an embodiment, cladding section 9200coupled to low resistance section 584 is copper tubing with a thicknessof about 0.32 cm (about ⅛ inch) and an inside diameter of about 2.5 cm.In an embodiment, cladding section 9200 coupled to conduit 582 is coppertubing with a thickness of about 0.32 cm (about ⅛ inch) and an outsidediameter of about 7.3 cm. In certain embodiments, cladding section 9200has a thickness between about 0.20 cm and about 1.2 cm.

[0975] In certain embodiments, cladding section 9200 is brazed to lowresistance section 584 and/or conduit 582. In other embodiments,cladding section 9200 may be welded to low resistance section 584 and/orconduit 582. In one embodiment, cladding section 9200 is Everdur®(silicon bronze) welded to low resistance section 584 and/or conduit582. Cladding section 9200 may be brazed or welded to low resistancesection 584 and/or conduit 582 depending on the types of materials usedin the cladding section, the low resistance conductor, and the conduit.For example, cladding section 9200 may include copper that is Everdur®welded to low resistance section 584, which includes carbon steel. Insome embodiments, cladding section 9200 may be pre-oxidized to inhibitcorrosion of the cladding section during use.

[0976] Using cladding section 9200 coupled to low resistance section 584and/or conduit 582 may inhibit a significant temperature rise in theoverburden of a formation during use of the heat source (i.e., reduceheat losses to the overburden). For example, using a copper claddingsection of about 0.3 cm thickness may decrease the electrical resistanceof a carbon steel low resistance conductor by a factor of about 20. Thelowered resistance in the overburden section of the heat source mayprovide a relatively small temperature increase adjacent to the wellborein the overburden of the formation. For example, supplying a current ofabout 500 A into an approximately 1.9 cm diameter low resistanceconductor (schedule 40 carbon steel pipe) with a copper cladding ofabout 0.3 cm thickness produces a maximum temperature of about 93° C. atthe low resistance conductor. This relatively low temperature in the lowresistance conductor may transfer relatively little heat to theformation. For a fixed voltage at the power source, lowering theresistance of the low resistance conductor may increase the transfer ofpower into the heated section of the heat source (e.g., conductor 580).For example, a 600 volt power supply may be used to supply power to aheat source through about a 300 m overburden and into about a 260 mheated section. This configuration may supply about 980 watts per meterto the heated section. Using a copper cladding section of about 0.3 cmthickness with a carbon steel low resistance conductor may increase thetransfer of power into the heated section by up to about 15% compared tousing the carbon steel low resistance conductor only.

[0977] In some embodiments, cladding section 9200 may be coupled toconductor 580 and/or conduit 582 by a “tight fit tubing” (TFT) method.TFT is commercially available from vendors such as Kuroki (Japan) orKarasaki Steel (Japan). The TFT method includes cryogenically cooling aninner pipe or conduit, which is a tight fit to an outer pipe. The cooledinner pipe is inserted into the heated outer pipe or conduit. Theassembly is then allowed to return to an ambient temperature. In somecases, the inner pipe can be hydraulically expanded to bond tightly withthe outer pipe.

[0978] Another method for coupling a cladding section to a conductor ora conduit may include an explosive cladding method. In explosivecladding, an inner pipe is slid into an outer pipe. Primer cord or othertype of explosive charge may be set off inside the inner pipe. Theexplosive blast may bond the inner pipe to the outer pipe.

[0979] Electromagnetically formed cladding may also be used for claddingsection 9200. An inner pipe and an outer pipe may be placed in a waterbath. Electrodes attached to the inner pipe and the outer pipe may beused to create a high potential between the inner pipe and the outerpipe. The potential may cause sudden formation of bubbles in the baththat bond the inner pipe to the outer pipe.

[0980] In another embodiment, cladding section 9200 may be arc welded toa conductor or conduit. For example, copper may be arc deposited and/orwelded to a stainless steel pipe or tube.

[0981] In some embodiments, cladding section 9200 may be formed withplasma powder welding (PPW). PPW formed material may be obtained fromDaido Steel Co. (Japan). In PPW, copper powder is heated to form aplasma. The hot plasma may be moved along the length of a tube (e.g., astainless steel tube) to deposit the copper and form the coppercladding.

[0982] Cladding section 9200 may also be formed by billet co-extrusion.A large piece of cladding material may be extruded along a pipe to forma desired length of cladding along the pipe.

[0983] In certain embodiments, forge welding (e.g., shielded active gaswelding) may be used to form claddings section 9200 on a conductorand/or conduit. Forge welding may be used to form a uniform weld throughthe cladding section and the conductor or conduit.

[0984] Another method is to start with strips of copper and carbon steelthat are bonded to together by tack welding or another suitable method.The composite strip is drawn through a shaping unit to form acylindrically shaped tube. The cylindrically shaped tube is seam weldedlongitudinally. The resulting tube may be coiled onto a spool.

[0985] Another possible embodiment for reducing the electricalresistance of the conductor in the overburden is to form low resistancesection 584 from low resistance metals (e.g., metals that are used incladding section 9200). A polymer coating may be placed on some of thesemetals to inhibit corrosion of the metals (e.g., to inhibit corrosion ofcopper or aluminum by hydrogen sulfide).

[0986] Increasing the emissivity of a conductive heat source mayincrease the efficiency at which heat is transferred to a formation. Anemissivity of a surface affects the amount of radiative heat emittedfrom the surface and the amount of radiative heat absorbed by thesurface. In general, the higher the emissivity a surface has, thegreater the radiation from the surface or the absorption of heat by thesurface. Thus, increasing the emissivity of a surface increases theefficiency of heat transfer because of the increased radiation of energyfrom the surface into the surroundings. For example, increasing theemissivity of a conductor in a conductor-in-conduit heat source mayincrease the efficiency at which heat is transferred to the conduit, asshown by the following equation: $\begin{matrix}{{\overset{.}{Q} = \frac{2\quad \pi \quad r_{1}{\sigma ( {T_{1}^{4} - T_{2}^{4}} )}}{\frac{1}{ɛ_{1}} + {( \frac{r_{1}}{r_{2}} )( {\frac{1}{ɛ_{2}} - 1} )}}}\quad;} & (30)\end{matrix}$

[0987] where, {dot over (Q)} is the rate of heat transfer between acylindrical conductor and a conduit, r₁ is the radius of the conductor,r₂ is the radius of the conduit, T₁ is the temperature at the conductor,T₂ is the temperature at the conduit, σ is the Stefan-Boltzmann constant(5.670×10⁻⁸J·K⁻⁴·m⁻²·s⁻¹), ε₁ is the emissivity of the conductor, and ε₂is the emissivity of the conduit. According to EQN. 30, increasing theemissivity of the conductor increases the heat transfer between theconductor and the conduit. Accordingly, for a constant heat transferrate, increasing the emissivity of the conductor decreases thetemperature difference between the conductor and the conduit (i.e.,increases the temperature of the conduit for a given conductortemperature). Increasing the temperature of the conduit increases theamount of heat transfer to the formation.

[0988] In an embodiment, a conductor and/or conduit may be treated toincrease the emissivity of the conductor and/or conduit materials.Treating the conductor and/or conduit may include roughening a surfaceof the conductor or conduit and/or oxidizing the conductor or conduit.In some embodiments, a conductor and/or conduit may be roughened and/oroxidized prior to assembly of a heat source. In some embodiments, aconductor and/or conduit may be roughened and/or oxidized after assemblyand/or installation into a formation (e.g., an oxidizing fluid may beintroduced into an annular space between the conductor and the conduitwhen heating a portion of the formation to pyrolysis temperature so thatthe heat generated in the conductor oxidizes the conductor and theconduit). The treatment method may be used to treat inner surfacesand/or outer surfaces, or portions thereof, of conductors or conduits.In certain embodiments, the outer surface of a conductor and the innersurface of a conduit are treated to increase the emissivities of theconductor and the conduit.

[0989] In an embodiment, surfaces of a conductor, or a portion of thesurface, may be roughened. The roughened surface of the conductor may bethe outer surface of the conductor. The surface of the conductor may beroughened by, but is not limited to being roughened by, sandblasting orbeadblasting the surface, peening the surface, emery grinding thesurface, or using an electrostatic discharge method on the surface. Forexample, the surface of the conductor may be sand blasted with fineparticles to roughen the surface. The conductor may also be treated bypre-oxidizing the surface of the conductor (i.e., heating the conductorto an oxidation temperature before use of the conductor). Pre-oxidizingthe surface of the conductor may include heating the conductor to atemperature between about 850° C. and about 950° C. The conductor may beheated in an oven or furnace. The conductor may be heated in anoxidizing atmosphere (e.g., an oven with a charge of an oxidizing fluidsuch as air). In an embodiment, a 304H stainless steel conductor isheated in a furnace at a temperature of about 870° C. for about 2 hours.If the surface of the 304H stainless steel conductor is roughened priorto heating the conductor in the furnace, the emissivity of the 304Hstainless steel conductor may be increased from about 0.5 to about 0.85.Increasing the emissivity of the conductor may reduce an operatingtemperature of the conductor. Operating the conductor at lowertemperatures may increase an operational lifetime of the conductor. Forexample, operating the conductor at lower temperatures may reduce creepand/or corrosion.

[0990] In some embodiments, applying a coating to a conductor or conduitmay increase the emissivity of a conductor or a conduit and increase theefficiency of heat transfer to the formation. An electrically insulatingand thermally conductive coating may be placed on a conductor and/orconduit. The electrically insulating coating may inhibit arcing betweenthe conductor and the conduit. Arcing between the conductor and theconduit may cause shorting between the conductor and the conduit. Arcingmay also produce hot spots and/or cold spots on either the conductor orthe conduit. In some embodiments, a coating or coatings on portions of aconduit and/or a conductor may increase emissivity, electricallyinsulate, and promote thermal conduction.

[0991] As shown in FIG. 66, conductor 580 and conduit 582 may be placedin opening 514 in hydrocarbon layer 516. In an embodiment, anelectrically insulative, thermally conductive coating is placed onconductor 580 and conduit 582 (e.g., on an outside surface of theconductor and an inside surface of the conduit). In some embodiments,the electrically insulative, thermally conductive coating is placed onconductor 580. In other embodiments, the electrically insulative,thermally conductive coating is placed on conduit 582. The electricallyinsulative, thermally conductive coating may electrically insulateconductor 580 from conduit 582. The electrically insulative, thermallyconductive coating may inhibit arcing between conductor 580 and conduit582. In certain embodiments, the electrically insulative, thermallyconductive coating maintains an emissivity of conductor 580 or conduit582 (i.e., inhibits the emissivity of the conductor or conduit fromdecreasing). In other embodiments, the electrically insulative,thermally conductive coating increases an emissivity of conductor 580and/or conduit 582. The electrically insulative, thermally conductivecoating may include, but is not limited to, oxides of silicon, aluminum,and zirconium, or combinations thereof. For example, silicon oxide maybe used to increase an emissivity of a conductor or conduit whilealuminum oxide may be used to provide better electrical insulation andthermal conductivity. Thus, a combination of silicon oxide and aluminumoxide may be used to increase emissivity while providing improvedelectrical insulation and thermal conductivity. In an embodiment,aluminum oxide is coated on conductor 580 to electrically insulate theconductor followed by a coating of silicon oxide to increase theemissivity of the conductor.

[0992] In an embodiment, the electrically insulative, thermallyconductive coating is sprayed on conductor 580 or conduit 582. Thecoating may be sprayed on during assembly of the conductor-in-conduitheat source. In some embodiments, the coating is sprayed on beforeassembling the conductor-in-conduit heat source. For example, thecoating may be sprayed on conductor 580 or conduit 582 by a manufacturerof the conductor or conduit. In certain embodiments, the coating issprayed on conductor 580 or conduit 582 before the conductor or conduitis coiled onto a spool for installation. In other embodiments, thecoating is sprayed on after installation of the conductor-in-conduitheat source.

[0993] In a heat source embodiment, a perforated conduit may be placedin the opening formed in the oil shale formation proximate and externalto the conduit of a conductor-in-conduit heater. The perforated conduitmay remove fluids formed in an opening in the formation to reducepressure adjacent to the heat source. A pressure may be maintained inthe opening such that deformation of the first conduit is inhibited. Insome embodiments, the perforated conduit may be used to introduce afluid into the formation adjacent to the heat source. For example, insome embodiments, hydrogen gas may be injected into the formationadjacent to selected heat sources to increase a partial pressure ofhydrogen during in situ conversion.

[0994]FIG. 88 illustrates an embodiment of a conductor-in-conduit heaterthat may heat an oil shale formation. Second conductor 586 may bedisposed in conduit 582 in addition to conductor 580. Second conductor586 may be coupled to conductor 580 using connector 587 located near alowermost surface of conduit 582. Second conductor 586 may be a returnpath for the electrical current supplied to conductor 580. For example,second conductor 586 may return electrical current to wellhead 690through low resistance second conductor 588 in overburden casing 541.Second conductor 586 and conductor 580 may be formed of elongatedconductive material. Second conductor 586 and conductor 580 may be astainless steel rod having a diameter of approximately 2.4 cm. Connector587 may be flexible. Conduit 582 may be electrically isolated fromconductor 580 and second conductor 586 using centralizers 581. The useof a second conductor may eliminate the need for a sliding connector.The absence of a sliding connector may extend the life of the heater.The absence of a sliding connector may allow for isolation of appliedpower from hydrocarbon layer 516.

[0995] In a heat source embodiment that utilizes second conductor 586,conductor 580 and the second conductor may be coupled by a flexibleconnecting cable. The bottom of the first and second conductor may haveincreased thicknesses to create low resistance sections. The flexibleconnector may be made of stranded copper covered with rubber insulation.

[0996] In a heat source embodiment, a first conductor and a secondconductor may be coupled to a sliding connector within a conduit. Thesliding connector may include insulating material that inhibitselectrical coupling between the conductors and the conduit. The slidingconnector may accommodate thermal expansion and contraction of theconductors and conduit relative to each other. The sliding connector maybe coupled to low resistance sections of the conductors and/or to a lowtemperature portion of the conduit.

[0997] In a heat source embodiment, the conductor may be formed ofsections of various metals that are welded or otherwise joined together.The cross-sectional area of the various metals may be selected to allowthe resulting conductor to be long, to be creep resistant at highoperating temperatures, and/or to dissipate desired amounts of heat perunit length along the entire length of the conductor. For example, afirst section may be made of a creep resistant metal (such as, but notlimited to, Inconel 617 or HR120), and a second section of the conductormay be made of 304 stainless steel. The creep resistant first sectionmay help to support the second section. The cross-sectional area of thefirst section may be larger than the cross-sectional area of the secondsection. The larger cross-sectional area of the first section may allowfor greater strength of the first section. Higher resistivity propertiesof the first section may allow the first section to dissipate the sameamount of heat per unit length as the smaller cross-sectional areasecond section.

[0998] In some embodiments, the cross-sectional area and/or the metalused for a particular conduit section may be chosen so that a particularsection provides greater (or lesser) heat dissipation per unit lengththan an adjacent section. More heat may be provided near an interfacebetween a hydrocarbon layer and a non-hydrocarbon layer (e.g., theoverburden and the hydrocarbon layer and/or an underburden and thehydrocarbon layer) to counteract end effects and allow for more uniformheat dissipation into the oil shale formation.

[0999] In a heat source embodiment, a conduit may have a variable wallthickness. Wall thickness may be thickest adjacent to portions of theformation that do not need to be fully heated. Portions of formationthat do not need to be fully heated may include layers of formation thathave low grade, little, or no hydrocarbon material.

[1000] In an embodiment of heat sources placed in a formation, a firstconductor, a second conductor and a third conductor may be electricallycoupled in a 3-phase Y electrical configuration. Each of the conductorsmay be a part of a conductor-in-conduit heater. The conductor-in-conduitheaters may be located in separate wellbores within the formation. Theouter conduits may be electrically coupled together or conduits may beconnected to ground. The 3-phase Y electrical configuration may providea safer and more efficient method to heat an oil shale formation thanusing a single conductor. The first, second, and third conduits may beelectrically isolated from the first, second, and third conductors. Eachconductor-in-conduit heater in a 3-phase Y electrical configuration maybe dimensioned to generate approximately 650 watts per meter ofconductor to approximately 1650 watts per meter of conductor.

[1001] Heat may be generated by the conductor-in-conduit heater withinan open wellbore. Generated heat may radiatively heat a portion of anoil shale formation adjacent to the conductor-in-conduit heater. To alesser extent, gas conduction adjacent to the conductor-in-conduitheater heats the portion of the formation. Using an open wellborecompletion may reduce casing and packing costs associated with fillingthe opening with a material to provide conductive heat transfer betweenthe insulated conductor and the formation. In addition, heat transfer byradiation may be more efficient than heat transfer by conduction in aformation, so the heaters may be operated at lower temperatures usingradiative heat transfer. Operating at a lower temperature may extend thelife of the heat source and/or reduce the cost of material needed toform the heat source.

[1002] The conductor-in-conduit heater may be installed in opening 514.In an embodiment, the conductor-in-conduit heater may be installed intoa well by sections. For example, a first section of theconductor-in-conduit heater may be suspended in a wellbore by a rig. Thesection may be about 12 m in length. A second section (e.g., ofsubstantially similar length) may be coupled to the first section in thewell. The second section may be coupled by welding the second section tothe first section and/or with threads disposed on the first and secondsection. An orbital welder disposed at the wellhead may weld the secondsection to the first section. The first section may be lowered into thewellbore by the rig. This process may be repeated with subsequentsections coupled to previous sections until a heater of desired lengthis placed in the wellbore. In some embodiments, three sections may bewelded together prior to being placed in the wellbore. The welds may beformed and tested before the rig is used to attach the three sections toa string already placed in the ground. The three sections may be liftedby a crane to the rig. Having three sections already welded together mayreduce installation time of the heat source.

[1003] Assembling a heat source at a location proximate a formation(e.g., at the site of a formation) may be more economical than shippinga pre-formed heat source and/or conduits to the oil shale formation. Forexample, assembling the heat source at the site of the formation mayreduce costs for transporting assembled heat sources over longdistances. In addition, heat sources may be more easily assembled invarying lengths and/or of varying materials to meet specific formationrequirements at the formation site. For example, a portion of a heatsource that is to be heated may be made of a material (e.g., 304stainless steel or other high temperature alloy) while a portion of theheat source in the overburden may be made of carbon steel. Forming theheat source at the site may allow the heat source to be specificallymade for an opening in the formation so that the portion of the heatsource in the overburden is carbon steel and not a more expensive, heatresistant alloy. Heat source lengths may vary due to varying formationlayer depths and formation properties. For example, a formation may havea varying thickness and/or may be located underneath rolling terrain,uneven surfaces, and/or an overburden with a varying thickness. Heatsources of varying length and of varying materials may be assembled onsite in lengths determined by the depth of each opening in theformation.

[1004]FIG. 89 depicts an embodiment for assembling aconductor-in-conduit heat source and installing the heat source in aformation. The conductor-in-conduit heat source may be assembled inassembly facility 8650. In some embodiments, the heat source isassembled from conduits shipped to the formation site. In otherembodiments, heat sources may be made from plate stock that is formedinto conduits at the assembly facility. An advantage of forming aconduit at the assembly facility may be that a surface of plate stockmay be treated with a desired coating (e.g., a coating that allows theemissivity to approach one) or cladding (e.g., copper cladding) beforeforming the conduit so that the treated surface is an inside surface ofthe conduit. In some embodiments, portions of heat sources may be formedfrom plate stock at the assembly facility, while other portions of theheat source may be formed from conduits shipped to the formation site.

[1005] Individual conductor-in-conduit heat source 8652 may includeconductor 580 and conduit 582 as shown in FIG. 90. In an embodiment,conductor 580 and conduit 582 heat sources may be made of a number ofjoined together sections. In an embodiment, each section is a standard40 ft (12.2 m) section of pipe. Other section lengths may also be formedand/or utilized. In addition, sections of conductor 580 and/or conduit582 may be treated in assembly facility 8650 before, during, or afterassembly. The sections may be treated, for example, to increase anemissivity of the sections by roughening and/or oxidation of thesections.

[1006] Each conductor-in-conduit heat source 8652 may be assembled in anassembly facility. Components of conductor-in-conduit heat source 8652may be placed on or within individual conductor-in-conduit heat source8652 in the assembly facility. Components may include, but are notlimited to, one or more centralizers, low resistance sections, slidingconnectors, insulation layers, and coatings, claddings, or couplingmaterials.

[1007] As shown in FIG. 89, each individual conductor-in-conduit heatsource 8652 may be coupled to at least one individualconductor-in-conduit heat source 8652 at coupling station 8656 to formconductor-in-conduit heat source of desired length 8654. The desiredlength may be, for example, a length of a conductor-in-conduit heatsource specified for a selected opening in a formation. In certainembodiments, coupling individual conductor-in-conduit heat source 8652to at least one additional individual conductor-in-conduit heat source8652 includes welding the individual conductor-in-conduit heat source toat least one additional individual conductor-in-conduit heat source. Inone embodiment, welding each individual conductor-in-conduit heat source8652 to an additional individual conductor-in-conduit heat source isaccomplished by forge welding two adjacent sections together.

[1008] In some embodiments, sections of welded togetherconductor-in-conduit heat source of desired length 8654 are placed on abench, holding tray or in an opening in the ground until the entirelength of the heat source is completed. Weld integrity may be tested aseach weld is formed. For example, weld integrity may be tested by anon-destructive testing method such as x-ray testing, acoustic testing,and/or electromagnetic testing. After an entire length ofconductor-in-conduit heat source of desired length 8654 is completed,the conductor-in-conduit heat source of desired length may be coiledonto spool 8660 in a direction of arrow 8662. Coilingconductor-in-conduit heat source of desired length 8654 may make theheat source easier to transport to an opening in a formation. Forexample, conductor-in-conduit heat source of desired length 8654 may bemore easily transported by truck or train to an opening in theformation.

[1009] In some embodiments, a set length of welded togetherconductor-in-conduit may be coiled onto spool 8660 while other sectionsare being formed at coupling station 8656. In some embodiments, theassembly facility may be a mobile facility (e.g., placed on one or moretrain cars or semi-trailers) that can be moved to an opening in aformation. After forming a welded together length ofconductor-in-conduit with components (e.g., centralizers, coatings,claddings, sliding connectors), the conductor-in-conduit length may belowered into the opening in the formation.

[1010] In certain embodiments, conductor-in-conduit heat source ofdesired length 8654 may be tested at testing station 8658 before coilingthe heat source. Testing station 8658 may be used to test a completedconductor-in-conduit heat source of desired length 8654 or sections ofthe conductor-in-conduit heat source of desired length. Testing station8658 may be used to test selected properties of conductor-in-conduitheat source of desired length 8654. For example, testing station 8658may be used to test properties such as, but not limited to, electricalconductivity, weld integrity, thermal conductivity, emissivity, andmechanical strength. In one embodiment, testing station 8658 is used totest weld integrity with an Electro-Magnetic Acoustic Transmission(EMAT) weld inspection technique.

[1011] Conductor-in-conduit heat source of desired length 8654 may becoiled onto spool 8660 for transporting from assembly facility 8650 toan opening in a formation and installation into the opening. In anembodiment, assembly facility 8650 is located at a site of theformation. For example, assembly facility 8650 may be part of a surfacefacility used to treat fluids from the formation or located a proximateto the formation (e.g., less than about 110 km from the formation or, insome embodiments, less than about 20 km or less than about 30 km). Othertypes of heat sources (e.g., insulated conductor heat sources, naturaldistributed combustor heat sources, etc.) may also be assembled inassembly facility 8650. These other heat sources may also be spooledonto spool 8660, transported to an opening in a formation, and installedinto the opening as is described for conductor-in-conduit heat source ofdesired length 8654.

[1012] Transportation of conductor-in-conduit heat source of desiredlength 8654 to an opening in a formation is represented by arrow 8664 inFIG. 89. Transporting conductor-in-conduit heat source of desired length8654 may include transporting the heat source on a bed, trailer, a cartof a truck or train, or a coiled tubing unit. In some embodiments, morethan one heat source may be placed on the bed. Each heat source may beinstalled in a separate opening in the formation. In one embodiment, atrain system (e.g., rail system) may be set up to transport heat sourcesfrom assembly facility 8650 to each of the openings in the formation. Insome instances, a lift and move track system may be used in which traintracks are lifted and moved to another location after use in onelocation.

[1013] After spool 8660 with conductor-in-conduit heat source of desiredlength 8654 has been transported to opening 514, the heat source may beuncoiled and installed into the opening in a direction of arrow 8666.Conductor-in-conduit heat source of desired length 8654 may be uncoiledfrom spool 8660 while the spool remains on the bed of a truck or train.In some embodiments, more than one conductor-in-conduit heat source ofdesired length 8654 may be installed at one time. In one embodiment,more than one heat source may be installed into one opening 514. Spool8660 may be re-used for additional heat sources after installation ofconductor-in-conduit heat source of desired length 8654. In someembodiments, spool 8660 may be used to removed conductor-in-conduit heatsource of desired length 8654 from the opening. Conductor-in-conduitheat source of desired length 8654 may be re-coiled onto spool 8660 asthe heat source is removed from opening 514. Subsequently,conductor-in-conduit heat source of desired length 8654 may bere-installed from spool 8660 into opening 514 or transported to analternate opening in the formation and installed the alternate opening.

[1014] In certain embodiments, conductor-in-conduit heat source ofdesired length 8654, or any heat source (e.g., an insulated conductorheat source), may be installed such that the heat source is removablefrom opening 514. The heat source may be removable so that the heatsource can be repaired or replaced if the heat source fails or breaks.In other instances, the heat source may be removed from the opening andtransported and reused in another opening in the formation (or in adifferent formation) at a later time. Being able to remove, replace,and/or reuse a heat source may be economically favorable for reducingequipment and/or operating costs. In addition, being able to remove andreplace an ineffective heater may eliminate the need to form wellboresin close proximity to existing wellbores that have failed heaters in aheated or heating formation.

[1015] In some embodiments, a conduit of a desired length may be placedinto opening 514 before a conductor of the desired length. The conductorand the conduit of the desired length may be assembled in assemblyfacility 8650. The conduit of the desired length may be installed intoopening 514. After installation of the conduit of the desired length,the conductor of the desired length may be installed into opening 514.In an embodiment, the conduit and the conductor of the desired lengthare coiled onto a spool in assembly facility 8650 and uncoiled from thespool for installation into opening 514. Components (e.g., centralizers581, sliding connectors 583, etc.) may be placed on the conductor orconduit as the conductor is installed into the conduit and opening 514.

[1016] In certain embodiments, centralizer 581 may include at least twoportions coupled together to form the centralizer (e.g., “clam shell”centralizers). In one embodiment, the portions are placed on a conductorand coupled together as the conductor is installed into a conduit oropening. The portions may be coupled with fastening devices such as, butnot limited to, clamps, bolts, screws, snap-locks, and/or adhesive. Theportions may be shaped such that a first portion fits into a secondportion. For example, an end of the first portion may have a slightlysmaller width than an end of the second portion so that the ends overlapwhen the two portions are coupled.

[1017] In some embodiments, low resistance section 584 is coupled toconductor-in-conduit heat source of desired length 8654 in assemblyfacility 8650. In other embodiments, low resistance section 584 iscoupled to conductor-in-conduit heat source of desired length 8654 afterthe heat source is installed into opening 514. Low resistance section584 of a desired length may be assembled in assembly facility 8650. Anassembled low resistance conductor may be coiled onto a spool. Theassembled low resistance conductor may be uncoiled from the spool andcoupled to conductor-in-conduit heat source of desired length 8654 afterthe heat source is installed in opening 514. In another embodiment, lowresistance section 584 is assembled as the low resistance conductor iscoupled to conductor-in-conduit heat source of desired length 8654 andinstalled into opening 514. Conductor-in-conduit heat source of desiredlength 8654 may be coupled to a support after installation so that lowresistance section 584 is coupled to the installed heat source.

[1018] Assembling a desired length of a low resistance conductor mayinclude coupling individual low resistance conductors together. Theindividual low resistance conductors may be plate stock conductorsobtained from a manufacturer. The individual low resistance conductorsmay be coupled to an electrically conductive material to lower theelectrical resistance of the low resistance conductor. The electricallyconductive material may be coupled to the individual low resistanceconductor before assembly of the desired length of low resistanceconductor. In one embodiment, the individual low resistance conductorsmay have threaded ends that are coupled together. In another embodiment,the individual low resistance conductors may have ends that are weldedtogether. Ends of the individual low resistance conductors may be shapedsuch that an end of a first individual low resistance conductor fitsinto an end of a second individual low resistance conductor. Forexample, an end of a first individual low resistance conductor may be afemale-shaped end while an end of a second individual low resistanceconductor is a male-shaped end.

[1019] In another embodiment, a conductor-in-conduit heat source of adesired length may be assembled at a wellbore (or opening) in aformation and installed into the wellbore as the conductor-in-conduitheat source is assembled. Individual conductors may be coupled to form afirst section of a conductor of desired length. Similarly, conduits maybe coupled to form a first section of a conduit of desired length. Thefirst formed sections of the conductor and the conduit may be installedinto the wellbore. The first formed sections of the conductor and theconduit may be electrically coupled at a first end that is installedinto the wellbore. The first sections of the conductor and conduit may,in some embodiments, be coupled substantially simultaneously. Additionalsections of the conductor and/or conduit may be formed during or afterinstallation of the first formed sections. The additional sections ofthe conductor and/or conduit may be coupled to the first formed sectionsof the conductor and/or conduit and installed into the wellbore.Centralizers and/or other components may be coupled to sections of theconductor and/or conduit and installed with the conductor and theconduit into the wellbore.

[1020] A method for coupling conductors or conduits may include a forgewelding method (e.g., shielded active gas (SAG) welding). In anembodiment, forge welding includes arranging ends of the conductorsand/or conduits that are to be interconnected at a selected distance.Seals may be formed against walls of the conduit and/or conductor todefine a chamber. A flushing, reducing fluid may be introduced into thechamber. Each end within the chamber may be heated and moved towardsanother end until the heated ends contact each other. Contacting theheated ends may form a forge weld between the heated ends. The flushing,reducing fluid mixture may include less than 25% by volume of a reducingagent and more than 75% by volume of a substantially inert gas. Theflushing, reducing fluid may inhibit oxidation reactions that canadversely affect weld integrity.

[1021] A flushing fluid mixture with less than 25% by volume of areducing fluid (e.g., hydrogen and/or carbon monoxide) and more than 75%by volume of a substantially inert gas (e.g., nitrogen, argon, and/orcarbon dioxide) may be non-explosive when the flushing fluid mixturecomes into contact with air at elevated temperatures needed to form theforge weld. In some embodiments, the reducing agent may be or includeborax powder and/or beryllium or alkaline hydrites. The flushing fluidmixture may contain a sufficient amount of a reducing gas to flush offoxidized skin from the hot ends that are to be interconnected. In someembodiments, the non-explosive flushing fluid mixture includes between2% by volume and 10% by volume of the reducing fluid and between 90% byvolume and 98% by volume of the substantially inert gas. In certainembodiments, the mixture includes about 5% by volume of the reducingfluid and about 95% by volume of the substantially inert gas. In oneembodiment, a non-explosive flushing fluid mixture includes about 95% byvolume of nitrogen and about 5% by volume of hydrogen. The non-explosiveflushing fluid mixture may also include less than 100 ppm H₂O and/or O₂or, in some cases, less than 15 ppm H₂O and/or O₂.

[1022] A substantially inert gas used during a forge welding procedureis a gas that does not significantly react with the metals to be forgedwelded at the pressures and temperatures used during forge welding.Substantially inert gas may be, but is not limited to, noble gases(e.g., helium and argon), nitrogen or combinations thereof.

[1023] A non-explosive flushing fluid mixture may be formed in-situwithin the chamber. A coating on the conduits and/or conductors may bepresent and/or a solid may be placed in the chamber. When the conduitsand/or conductors are heated, the coating and/or solid may be react orphysically transform to the flushing fluid mixture.

[1024] In an embodiment, ends of conductors or conduits are heated bymeans of high frequency electrical heating. The ends may be maintainedat a predetermined spacing of between 1 mm and 4 mm from each other by agripping assembly while being heated. Electrical contacts may be pressedat circumferentially spaced intervals against the wall of each conduitand/or conductor adjacent to the end such that the electrical contactstransmit a high frequency electrical current in a substantiallycircumferential direction in the segment between the electricalcontacts.

[1025] To equalize the level of heating in a circumferential direction,each end may be heated by at least two pairs of electrodes. Theelectrodes of each pair may be pressed at substantially diametricallyopposite positions against walls of the conduits and/or conductors. Thedifferent pairs of electrodes at each end may be activated in analternating manner.

[1026] In one embodiment, two pairs of diametrically opposite electrodesare pressed at angular intervals of substantially 90° against walls ofthe conductors and conduits. In another embodiment, three pairs ofdiametrically opposite electrodes are pressed at angular intervals ofsubstantially 60° against the walls of the conductors and conduits. Inother embodiments, four, five, six or more pairs of diametricallyopposite electrodes may be used and activated in an alternating mannerto equalize the level of heating of the ends in the circumferentialdirection.

[1027] The use of two or more pairs of electrodes may reduce unequalheating of the pipe ends because of over heating of the walls in thedirect vicinity of the electrode. In addition, using two or more pairsof electrodes may reduce heating of the pipe wall halfway between theelectrodes.

[1028] In another embodiment, the ends may be heated by a directresistance heating method. The direct resistance heating method mayinclude transmitting a large current in an axial direction across theconduits and/or conductors while the conduits and/or conductors arepressed together. In another embodiment, the ends may be heated byinduction heating. Induction heating may include using external and/orinternal heating coils to create an electromagnetic field that induceselectrical currents in the conduits and/or conductors. The electricalscurrents may resistively heat the conduits.

[1029] The heating assembly may be used to give the forge welded ends apost weld heat treatment. The post weld heat treatment may includeproviding at least some heating to the ends such that the ends arecooled down at a predetermined temperature decrease rate (i.e., cooldown rate). In some embodiments, the assembly may be equipped with waterand/or forced air injectors to increase and/or control the cool downrate of the forge welded ends.

[1030] In certain embodiments, the quality of the forge weld formedbetween the interconnected conduits and/or conductors is inspected bymeans of an Electro-Magnetic Acoustic Transmission weld inspectiontechnique (EMAT). EMAT may include placing at least one electromagneticcoil adjacent to both sides of the forge welded joint. The coil may beheld at a predetermined distance from the conduits and/or conductorsduring the inspection process. The absence of physical contact betweenthe wall of the hot conduits and/or conductors and the coils of the EMATinspection tool may enable weld inspection immediately after the forgeweld joint has been made.

[1031]FIG. 91 shows an end of tubular 9150 around which two pairs ofdiametrically opposite electrodes 9152, 9153 and 9154, 9155 arearranged. Tubular 9150 may be a conduit or conductor. Tubular 9150 maybe made of electrically conductive material (e.g., stainless steel). Thefirst pair of electrodes 9152, 9153 may be pressed against the outersurface of tubular 9150 and transmit high frequency current 9156 throughthe wall of the tubular as illustrated by arrows 9157. An assembly offerrite bars 9158 may serve to enhance the current density in theimmediate vicinity of the ends of the tubular 9150 and of the adjacenttubular to which tubular 9150 is to be welded.

[1032]FIG. 92 depicts an embodiment with ends 9162, 9162A of twoadjacent tubulars 9150 and 9150A. Tubulars 9150 and 9150A may be heatedby two sets of diametrically opposite electrodes 9152, 9153, 9154, 9155and 9152A, 9153A, 9154A and 9155A, respectively. Tubular ends 9162 and9162A may be located at a few millimeters distant from each other duringa heating phase. The larger spacing of current density arrows 9157midway between electrodes 9152, 9153 illustrates that the currentdensity midway between these electrodes may be lower than the currentdensity adjacent to each of the electrodes. The lower current densitymidway between the electrodes may create a variation in the heating rateof the tubular ends 9162 and 9162A. To reduce a possible irregularheating rate, electrodes 9152, 9153 and 9152A, 9153A may be regularlylifted from the outer surface of tubulars 9150, 9150A while the otherelectrodes 9154, 9154A and 9155, 9155A are pressed against the outersurface of the tubulars 9150, 9150A and activated to transmit a highfrequency current through the ends of the tubulars. By sequentiallyactivating the two sets of diametrically opposite electrodes at eachtubular end, irregular heating of the tubular ends may be inhibited(i.e., heating of the tubular ends may be more uniform).

[1033] All electrodes 9152-9155 and 9152A-9155A shown in FIG. 92 may bepressed simultaneously against tubular ends 9150 and 9150A ifalternating current supplied to the electrodes is controlled such thatduring a first part of a current cycle the diametrically oppositeelectrode pairs 9152A, 9153A and 9154, 9155 transmit a positiveelectrical current as indicated by the “+” sign in FIG. 92, whereaselectrodes 9152, 9153, and 9154A, 9155A transmit a negative electricalcurrent as indicated by the “−” sign. During a second part of thealternating current cycle, electrodes 9152A, 9153A, and 9154, 9155transmit a negative electrical current, whereas electrodes 9152, 9153,and 9154A, 9155A transmit a positive current into tubulars 9150 and9150A. Controlling the alternating current in this manner may heattubular ends 9162 and 9162A in a substantially uniform manner.

[1034] The temperature of heated tubular ends 9162, 9162A may bemonitored by an infrared temperature sensor. When the monitoredtemperature has reached a temperature sufficient to make a forge weld,tubular ends 9162, 9162A may be pressed onto each other such that aforge weld is made. Tubular ends 9162, 9162A may be profiled and have asmaller wall thickness than other parts of tubulars 9150, 9150A tocompensate for the deformation of the tubular ends when the ends areabutted. Profiling the tubular ends may allow tubulars 9150, 9150A tohave a substantially uniform wall thickness at forge welded ends.

[1035] During the heating phase and while the ends of tubulars 9150,9150A are moved towards each other, the tubular ends may be encased,both internally and externally, in a chamber 9168. Chamber 9168 may befilled with a non-explosive flushing fluid mixture.

[1036] The non-explosive flushing fluid mixture may include more than75% by volume of nitrogen and less than 25% by volume of hydrogen. Inone embodiment, the non-explosive flushing fluid mixture forinterconnecting steel tubulars 9150, 9150A includes about 5% by volumeof hydrogen and about 95% by volume of nitrogen. The flushing fluidpressure in a part of chamber 9168 outside the tubulars 9150 and 9150Amay be higher than the flushing fluid pressure in a part of the chamber9168 within the interior of the tubulars such that throughout theheating process the flushing fluid flows along the ends of the tubularsas illustrated by arrows 9169 until the ends of the tubulars are forgedtogether. In some embodiments, flushing fluid may flow through thechamber.

[1037] Hydrogen in the flushing fluid may react with oxidized metal onthe ends 9162, 9162A of the tubulars 9150, 9150A so that formation of anoxidized skin is inhibited. Inhibition of an oxidized skin may allowformation of a forge weld with minimal amounts of corroded metalinclusions.

[1038] Laboratory experiments reveal that a good metallurgical bondbetween stainless steel tubulars may be obtained by forge welding with aflushing fluid containing about 5% by volume of hydrogen and about 95%by volume of nitrogen. Experiments also show that such a flushing fluidmixture may be non-explosive during and after forge welding. Two forgewelded stainless steel tubulars failed during at a location away fromthe forge weld when the tubulars were subjected to testing.

[1039] In an embodiment, the tubular ends are clamped throughout theforge welding process to a gripping assembly. Clamping the tubular endsmay maintain the tubular ends at a predetermined spacing of between 1 mmand 4 mm from each other during the heating phase. The gripping assemblymay include a mechanical stop that interrupts axial movement of theheated tubular ends during the forge welding process after the heatedtubular ends have moved a predetermined distance towards each other. Theheated tubular ends may be pressed into each other such that a highquality forge weld is created without significant deformation of theheated ends.

[1040] In certain embodiments, electrodes 9152-9155 and 9152A-9155A mayalso be activated to give the forged tubular ends a post weld heattreatment. Electrical power 9156 supplied to the electrodes during thepost weld heat treatment may be lower than during the heat up phasebefore the forge welding operation. Electrical power 9156 suppliedduring the post weld heat treatment may be controlled in conjunctionwith temperature measured by an infrared temperature sensor(s) such thatthe temperature of the forge welded tubular ends is decreased inaccordance with a predetermined temperature decrease or cooling cycle.

[1041] The quality of the forge weld may be inspected by a hybridelectromagnetic acoustic transmission technique which is known as EMAT.EMAT is described in U.S. Pat. Nos. 5,652,389 to Schaps et al.,5,760,307 to Latimer et al., 5,777,229 to Geier et al., and 6,155,117 toStevens et al., each of which is incorporated by reference as if fullyset forth herein. The EMAT technique makes use of an induction coilplaced at one side of the welded joint. The induction coil may inducemagnetic fields that generate electromagnetic forces in the surface ofthe welded joint. These forces may produce a mechanical disturbance bycoupling to the atomic lattice through a scattering process. Inelectromagnetic acoustic generation, the conversion may take placewithin a skin depth of material (i.e., the metal surface acts as atransducer). The reception may take place in a reciprocal way in areceiving coil. When the elastic wave strikes the surface of theconductor in the presence of a magnetic field, induced currents may begenerated in the receiving coil, similar to the operation of an electricgenerator. An advantage of the EMAT weld inspection technology is thatthe inductive transmission and receiving coils do not have to contactthe welded tubular. Thus, the inspection may be done soon after theforge weld is made (e.g., when the forge welded tubulars are still toohot to allow physical contact with an inspection probe).

[1042] Using the SAG method to weld tubular ends of heat sources mayinhibit changes in the metallurgy of the tubular materials. For example,the elemental composition of the weld joint may be substantially similarto the elemental composition of the tubulars. Inhibiting changes inmetallurgy may reduce the need for heat-treatment of the tubulars beforeuse of the tubulars. The SAG method also appears not to change the grainstructure of the near-weld section of the tubulars. Maintaining thegrain structure of the tubulars may inhibit corrosion and/or creep inthe tubulars during use.

[1043]FIG. 93 illustrates an end view of an embodiment of aconductor-in-conduit heat source heated by diametrically oppositeelectrodes. Conductor 580 may be placed within conduit 582. Conductor580 may be heated by two sets of diametrically opposite electrodes 9152,9153, 9154, 9155. Conduit 582 may be heated by two sets of diametricallyopposite electrodes 9172, 9173, 9174, 9175. Conductor 580 and conduits582 may be heated and forge welded together as described in theembodiments of FIGS. 91-92. In some embodiments, two ends of conductors580 are forged welded together and then two ends of conduits 582 areforged together in a second procedure.

[1044]FIG. 94 illustrates a cross-sectional representation of anembodiment of two sections of a conductor-in-conduit heat source beforebeing forge welded. During heating of conductors 580, 580A and conduits582, 582A and while the ends of the conductors and the conduits aremoved towards each other, ends of the conductors and conduits may beencased in a chamber 9176. Chamber 9176 may be filled with thenon-explosive flushing fluid mixture. Plugs 9178, 9178A may be placed inthe annular space between conductors 580, 580A and conduits 582, 582A.In an embodiment, the plugs may be inflated to seal the annular space.Plugs 9178, 9178A may inhibit the flow of the flushing fluid mixturethrough the annular space between conductors 580, 580A and conduits 582,582A. The flushing fluid pressure in a part of chamber 9176 outside theconduits 582, 582A may be higher than the flushing fluid pressure insidethe conduits and outside conductors 580, 580A. Similarly, the flushingfluid pressure outside conductors 580, 580A may be higher than theflushing fluid pressure inside the conductors. Due to the pressuredifferentials throughout the heating process, the flushing fluid tendsto flow along the ends of the tubulars as illustrated by arrows 9179until the ends of the conductors and conduits are forged together.

[1045]FIG. 95 depicts an embodiment of three horizontal heat sourcesplaced in a formation. Wellbore 9632 may be formed through overburden540 and into hydrocarbon layer 516. Wellbore 9632 may be formed by anystandard drilling method. In certain embodiments, wellbore 9632 isformed substantially horizontally in hydrocarbon layer 516. In someembodiments, wellbore 9632 may be formed at other angles withinhydrocarbon layer 516.

[1046] One or more conduits 9634 may be placed within wellbore 9632. Aportion of wellbore 9632 and/or second wellbores may include casings.Conduit 9634 may have a smaller diameter than wellbore 9632. In anembodiment, wellbore 9632 has a diameter of about 30.5 cm and conduit9634 has a diameter of about 14 cm. In an embodiment, an inside diameterof a casing in conduit 9634 may be about 12 cm. Conduits 9634 may haveextended sections 9635 that extend beyond the end of wellbore 9632 inhydrocarbon layer 516. Extended sections 9635 may be formed inhydrocarbon layer 516 by drilling or other wellbore forming methods. Inan embodiment, extended sections 9635 extend substantially horizontallyinto hydrocarbon layer 516. In certain embodiments, extended sections9635 may somewhat diverge as represented in FIG. 95.

[1047] Perforated casings 9636 may be placed in extended sections 9635of conduits 9634. Perforated casings 9636 may provide support for theextended sections so that collapse of wellbores is inhibited duringheating of the formation. Perforated casings 9636 may be steel (e.g.,carbon steel or stainless steel). Perforated casings 9636 may beperforated liners that expand within the wellbores (expandabletubulars). Expandable tubulars are described in U.S. Pat. Nos. 5,366,012to Lohbeck, and 6,354,373 to Vercaemer et al., each of which isincorporated by reference as if fully set forth herein. In anembodiment, perforated casings 9636 are formed by inserting a perforatedcasing into each of extended sections 9635 and expanding the perforatedcasing within each extended section. The perforated casing may beexpanded by pulling an expander tool shaped to push the perforatedcasing towards the wall of the wellbore (e.g., a pig) along the lengthof each extended section 9635. The expander tool may push eachperforated casing beyond the yield point of the perforated casing.

[1048] After installation of perforated casings 9636, heat sources 9638may be installed into extended sections 9635. Heat sources 9638 may beused to provide heat to hydrocarbon layer 516 along the length ofextended sections 9635. Heat sources 9638 may include heat sources suchas conductor-in-conduit heaters, insulated conductor heaters, etc. Insome embodiments, heat sources 9638 have a diameter of about 7.3 cm.Perforated casings 9636 may allow for production of formation fluid fromthe heat source wellbores. Installation of heat sources 9638 inperforated casings 9636 may also allow the heat sources to be removed ata later time. Heat sources 9638 may, for example, be removed for repair,replacement, and/or used in another portion of a formation.

[1049] In an embodiment, an elongated member may be disposed within anopening (e.g., an open wellbore) in an oil shale formation. The openingmay be an uncased opening in the oil shale formation. The elongatedmember may be a length (e.g., a strip) of metal or any other elongatedpiece of metal (e.g., a rod). The elongated member may include stainlesssteel. The elongated member may be made of a material able to withstandcorrosion at high temperatures within the opening.

[1050] An elongated member may be a bare metal heater. “Bare metal”refers to a metal that does not include a layer of electricalinsulation, such as mineral insulation, that is designed to provideelectrical insulation for the metal throughout an operating temperaturerange of the elongated member. Bare metal may encompass a metal thatincludes a corrosion inhibiter such as a naturally occurring oxidationlayer, an applied oxidation layer, and/or a film. Bare metal includesmetal with polymeric or other types of electrical insulation that cannotretain electrical insulating properties at typical operating temperatureof the elongated member. Such material may be placed on the metal andmay be thermally degraded during use of the heater.

[1051] An elongated member may have a length of about 650 m. Longerlengths may be achieved using sections of high strength alloys, but suchelongated members may be expensive. In some embodiments, an elongatedmember may be supported by a plate in a wellhead. The elongated membermay include sections of different conductive materials that are weldedtogether end-to-end. A large amount of electrically conductive weldmaterial may be used to couple the separate sections together toincrease strength of the resulting member and to provide a path forelectricity to flow that will not result in arcing and/or corrosion atthe welded connections. In some embodiments, different sections may beforge welded together. The different conductive materials may includealloys with a high creep resistance. The sections of differentconductive materials may have varying diameters to ensure uniformheating along the elongated member. A first metal that has a highercreep resistance than a second metal typically has a higher resistivitythan the second metal. The difference in resistivities may allow asection of larger cross-sectional area, more creep resistant first metalto dissipate the same amount of heat as a section of smallercross-sectional area second metal. The cross-sectional areas of the twodifferent metals may be tailored to result in substantially the sameamount of heat dissipation in two welded together sections of themetals. The conductive materials may include, but are not limited to,617 Inconel, HR-120, 316 stainless steel, and 304 stainless steel. Forexample, an elongated member may have a 60 meter section of 617 Inconel,60 meter section of HR-120, and 150 meter section of 304 stainlesssteel. In addition, the elongated member may have a low resistancesection that may run from the wellhead through the overburden. This lowresistance section may decrease the heating within the formation fromthe wellhead through the overburden. The low resistance section may bethe result of, for example, choosing a electrically conductive materialand/or increasing the cross-sectional area available for electricalconduction.

[1052] In a heat source embodiment, a support member may extend throughthe overburden, and the bare metal elongated member or members may becoupled to the support member. A plate, a centralizer, or other type ofsupport member may be located near an interface between the overburdenand the hydrocarbon layer. A low resistivity cable, such as a strandedcopper cable, may extend along the support member and may be coupled tothe elongated member or members. The low resistivity cable may becoupled to a power source that supplies electricity to the elongatedmember or members.

[1053]FIG. 96 illustrates an embodiment of a plurality of elongatedmembers that may heat an oil shale formation. Two or more (e.g., four)elongated members 600 may be supported by support member 604. Elongatedmembers 600 may be coupled to support member 604 using insulatedcentralizers 602. Support member 604 may be a tube or conduit. Supportmember 604 may also be a perforated tube. Support member 604 may providea flow of an oxidizing fluid into opening 514. Support member 604 mayhave a diameter between about 1.2 cm to about 4 cm and, in someembodiments, about 2.5 cm. Support member 604, elongated members 600,and insulated centralizers 602 may be disposed in opening 514 inhydrocarbon layer 516. Insulated centralizers 602 may maintain alocation of elongated members 600 on support member 604 such thatlateral movement of elongated members 600 is inhibited at temperatureshigh enough to deform support member 604 or elongated members 600.Elongated members 600, in some embodiments, may be metal strips of about2.5 cm wide and about 0.3 cm thick stainless steel. Elongated members600, however, may also include a pipe or a rod formed of a conductivematerial. Electrical current may be applied to elongated members 600such that elongated members 600 may generate heat due to electricalresistance.

[1054] Elongated members 600 may generate heat of approximately 650watts per meter of elongated members 600 to approximately 1650 watts permeter of elongated members 600. Elongated members 600 may be attemperatures of approximately 480° C. to approximately 815° C.Substantially uniform heating of an oil shale formation may be providedalong a length of elongated members 600 or greater than about 305 m or,maybe even greater than about 610 m.

[1055] Elongated members 600 may be electrically coupled in series.Electrical current may be supplied to elongated members 600 usinglead-in conductor 572. Lead-in conductor 572 may be coupled to wellhead690. Electrical current may be returned to wellhead 690 using lead-outconductor 606 coupled to elongated members 600. Lead-in conductor 572and lead-out conductor 606 may be coupled to wellhead 690 at surface 550through a sealing flange located between wellhead 690 and overburden540. The sealing flange may inhibit fluid from escaping from opening 514to the surface 550 and/or atmosphere. Lead-in conductor 572 and lead-outconductor 606 may be coupled to elongated members using a cold pintransition conductor. The cold pin transition conductor may include aninsulated conductor of low resistance. Little or no heat may begenerated in the cold pin transition conductor. The cold pin transitionconductor may be coupled to lead-in conductor 572, lead-out conductor606, and/or elongated members 600 by splices, mechanical connectionsand/or welds. The cold pin transition conductor may provide atemperature transition between lead-in conductor 572, lead-out conductor606, and/or elongated members 600. Lead-in conductor 572 and lead-outconductor 606 may be made of low resistance conductors so thatsubstantially no heat is generated from electrical current passingthrough lead-in conductor 572 and lead-out conductor 606.

[1056] Weld beads may be placed beneath the centralizers 602 on supportmember 604 to fix the position of the centralizers. Weld beads may beplaced on elongated members 600 above the uppermost centralizer to fixthe position of the elongated members relative to the support member(other types of connecting mechanisms may also be used). When heated,the elongated member may thermally expand downwards. The elongatedmember may be formed of different metals at different locations along alength of the elongated member to allow relatively long lengths to beformed. For example, a “U” shaped elongated member may include a firstlength formed of 310 stainless steel, a second length formed of 304stainless steel welded to the first length, and a third length formed of310 stainless steel welded to the second length. 310 stainless steel ismore resistive than 304 stainless steel and may dissipate approximately25% more energy per unit length than 304 stainless steel of the samedimensions. 310 stainless steel may be more creep resistant than 304stainless steel. The first length and the third length may be formedwith cross-sectional areas that allow the first length and third lengthsto dissipate as much heat as a smaller cross-sectional area of 304stainless steel. The first and third lengths may be positioned close towellhead 690. The use of different types of metal may allow theformation of long elongated members. The different metals may be, butare not limited to, 617 Inconel, HR120, 316 stainless steel, 310stainless steel, and 304 stainless steel.

[1057] Packing material 542 may be placed between overburden casing 541and opening 514. Packing material 542 may inhibit fluid flowing fromopening 514 to surface 550 and to inhibit corresponding heat lossestowards the surface. In some embodiments, overburden casing 541 may beplaced in cement 544 in overburden 540. In other embodiments, overburdencasing may not be cemented to the formation. Surface conductor 545 maybe disposed in cement 544. Support member 604 may be coupled to wellhead690 at surface 550. Centralizer 581 may maintain a location of supportmember 604 within overburden casing 541. Electrical current may besupplied to elongated members 600 to generate heat. Heat generated fromelongated members 600 may radiate within opening 514 to heat at least aportion of hydrocarbon layer 516.

[1058] The oxidizing fluid may be provided along a length of theelongated members 600 from oxidizing fluid source 508. The oxidizingfluid may inhibit carbon deposition on or proximate the elongatedmembers. For example, the oxidizing fluid may react with hydrocarbons toform carbon dioxide. The carbon dioxide may be removed from the opening.Openings 605 in support member 604 may provide a flow of the oxidizingfluid along the length of elongated members 600. Openings 605 may becritical flow orifices. In some embodiments, a conduit may be disposedproximate elongated members 600 to control the pressure in the formationand/or to introduce an oxidizing fluid into opening 514. Without a flowof oxidizing fluid, carbon deposition may occur on or proximateelongated members 600 or on insulated centralizers 602. Carbondeposition may cause shorting between elongated members 600 andinsulated centralizers 602 or hot spots along elongated members 600. Theoxidizing fluid may be used to react with the carbon in the formation.The heat generated by reaction with the carbon may complement orsupplement electrically generated heat.

[1059] In a heat source embodiment, a bare metal elongated member may beformed in a “U” shape (or hairpin) and the member may be suspended froma wellhead or from a positioner placed at or near an interface betweenthe overburden and the formation to be heated. In certain embodiments,the bare metal heaters are formed of rod stock. Cylindrical, highalumina ceramic electrical insulators may be placed over legs of theelongated members. Tack welds along lengths of the legs may fix theposition of the insulators. The insulators may inhibit the elongatedmember from contacting the formation or a well casing (if the elongatedmember is placed within a well casing). The insulators may also inhibitlegs of the “U” shaped members from contacting each other. High aluminaceramic electrical insulators may be purchased from Cooper Industries(Houston, Tex.,). In an embodiment, the “U” shaped member may be formedof different metals having different cross-sectional areas so that theelongated members may be relatively long and may dissipate a desiredamount of heat per unit length along the entire length of the elongatedmember.

[1060] Use of welded together sections may result in an elongated memberthat has large diameter sections near a top of the elongated member anda smaller diameter section or sections lower down a length of theelongated member. For example, an embodiment of an elongated member hastwo ⅞ inch (2.2 cm) diameter first sections, two ½ inch (1.3 cm) middlesections, and a ⅜ inch (0.95 cm) diameter bottom section that is bentinto a “U” shape. The elongated member may be made of materials withother cross-sectional shapes such as ovals, squares, rectangles,triangles, etc. The sections may be formed of alloys that will result insubstantially the same heat dissipation per unit length for eachsection.

[1061] In some embodiments, the cross-sectional area and/or the metalused for a particular section may be chosen so that a particular sectionprovides greater (or lesser) heat dissipation per unit length than anadjacent section. More heat dissipation per unit length may be providednear an interface between a hydrocarbon layer and a non-hydrocarbonlayer (e.g., the overburden and the hydrocarbon layer) to counteract endeffects and allow for more uniform heat dissipation into the hydrocarbonlayer. A higher heat dissipation may also be located at a lower end ofan elongated member to counteract end effects and allow for more uniformheat dissipation.

[1062] In certain embodiments, the wall thickness of portions of aconductor, or any electrically-conducting portion of a heater, may beadjusted to provide more or less heat to certain zones of a formation.In an embodiment, the wall thickness of a portion of the conductoradjacent to a lean zone (i.e., zone containing relatively little or nohydrocarbons) may be thicker than a portion of the conductor adjacent toa rich zone (i.e., hydrocarbon layer in which hydrocarbons are pyrolyzedand/or produced). Adjusting the wall thickness of a conductor to provideless heat to the lean zone and more heat to the rich zone may moreefficiently use electricity to heat the formation.

[1063]FIG. 97 illustrates a cross-sectional representation of anembodiment of a heater using two oxidizers. One or more oxidizers may beused to heat a hydrocarbon layer or hydrocarbon layers of a formationhaving a relatively shallow depth (e.g., less than about 250 m). Conduit6110 may be placed in opening 514 in a formation. Conduit 6110 may haveupper portion 6112. Upper portion 6112 of conduit 6110 may be placedprimarily in overburden 540 of the formation. A portion of conduit 6110may include high temperature resistant, non-corrosive materials (e.g.,316 stainless steel and/or 304 stainless steel). Upper portion 6112 ofconduit 6110 may include a less temperature resistant material (e.g.,carbon steel). A diameter of opening 514 and conduit 6110 may be chosensuch that a cross-sectional area of opening 514 outside of conduit 6110is approximately equal to a cross-sectional area inside conduit 6110.This may equalize pressures outside and inside conduit 6110. In anembodiment, conduit 6110 has a diameter of about 0.11 m and opening 514has a diameter of about 0.15 m.

[1064] Oxidizing fluid source 508 may provide oxidizing fluid 517 intoconduit 6110. Oxidizing fluid 517 may include hydrogen peroxide, air,oxygen, or oxygen enriched air. In an embodiment, oxidizing fluid source508 may include a membrane system that enriches air by preferentiallypassing oxygen, instead of nitrogen, through a membrane or membranes.First fuel source 6119 may provide fuel 6118 into first fuel conduit6116. First fuel conduit 6116 may be placed in upper portion 6112 ofconduit 6110. In some embodiments, first fuel conduit 6116 may be placedoutside conduit 6110. In other embodiments, conduit 6110 may be placedwithin first fuel conduit 6116. Fuel 6118 may include combustiblematerial including but not limited to, hydrogen, methane, ethane, otherhydrocarbon fluids, and/or combinations thereof. Fuel 6118 may includesteam to inhibit coking within the fuel conduit or proximate anoxidizer. First oxidizer 6120 may be placed in conduit 6110 at a lowerend of upper portion 6112. First oxidizer 6120 may oxidize at least aportion of fuel 6118 from first fuel conduit 6116 with at least aportion of oxidizing fluid 517. First oxidizer may be a burner such asan inline burner. Burners may be obtained from John Zink Company (Tulsa,Okla.) or Callidus Technologies (Tulsa, Okla.). First oxidizer 6120 mayinclude an ignition source such as a flame. First oxidizer 6120 may alsoinclude a flameless ignition source such as, for example, an electricigniter.

[1065] In some embodiments, fuel 6118 and oxidizing fluid 517 may becombined at the surface and provided to opening 514 through conduit6110. Fuel 6118 and oxidizing fluid 517 may be combined in a mixer,aerator, nozzle, or similar mixing device located at the surface. Insuch an embodiment, conduit 6110 provides both fuel 6118 and oxidizingfluid 517 into opening 514. Locating first oxidizer 6120 at or proximatethe upper portion of the section of the formation to be heated may tendto inhibit or decrease coking in one or more of the fuel conduits (e.g.,in first fuel conduit 6116).

[1066] Oxidation of fuel 6118 at first oxidizer 6120 will generate heat.The generated heat may heat fluids in a region proximate first oxidizer6120. The heated fluids may include fuel, oxidizing fluid, and oxidationproducts. The heated fluids may be allowed to transfer heat tohydrocarbon layer 6100 along a length of conduit 6110. The amount ofheat transferred from the heated fluids to the formation may varydepending on, for example, a temperature of the heated fluids. Ingeneral, the greater the temperature of the heated fluids, the more heatthat will be transferred to the formation. In addition, as heat istransferred from the heated fluids, the temperature of the heated fluidsdecreases. For example, temperatures of fluids in the oxidizer flame maybe about 1300° C. or above, and as the fluids reach a distance of about150 m from the oxidizer, temperatures of fluids may be, for example,about 750° C. Thus, the temperature of the heated fluids, and hence theheat transferred to the formation, decreases as the heated fluids flowaway from the oxidizer.

[1067] First insulation 6122 may be placed on lengths of conduit 6110proximate a region of first oxidizer 6120. First insulation 6122 mayhave a length of about 10 m to about 200 m (e.g., about 50 m). Inalternative embodiments, first insulation 6122 may have a length that isabout 10-40% of the length of conduit 6110 between any two oxidizers(e.g., between first oxidizer 6120 and second oxidizer 6130 in FIG. 97).A length of first insulation 6122 may vary depending on, for example,desired heat transfer rate to the formation, desired temperatureproximate the first oxidizer, and/or desired temperature profile alongthe length of conduit 6110. First insulation 6122 may have a thicknessthat varies (either continually or in step fashion) along its length. Incertain embodiments, first insulation 6122 may have a greater thicknessproximate first oxidizer 6120 and a reduced thickness at a desireddistance from the first oxidizer. The greater thickness of firstinsulation 6122 may preferentially reduce heat transfer proximate firstoxidizer 6120 as compared to a reduced thickness portion of theinsulation. Variable thickness insulation may allow for uniform orrelatively uniform heating of the formation adjacent to a heated portionof the heat source. In an embodiment, first insulation 6122 may have athickness of about 0.03 m proximate first oxidizer 6120 and a thicknessof about 0.015 m at a distance of about 10 m from the first oxidizer. Inthe embodiment, the heated portion of the conduit is about 300 m inlength, with insulation (first insulation 6122) being placed proximatethe upper 100 m portion of this length, and insulation (secondinsulation 6132) being placed proximate the lower 100 m portion of thislength.

[1068] A thickness of first insulation 6122 may vary depending on, forexample, a desired heating rate or a desired temperature within opening514 of hydrocarbon layer 6100. The first insulation may inhibit thetransfer of heat from the heated fluids to the formation in a regionproximate the insulating conduit. First insulation 6122 may also inhibitcharring and/or coking of hydrocarbons proximate first oxidizer 6120.First insulation 6122 may inhibit charring and/or coking by reducing anamount of heat transferred to the formation proximate the firstoxidizer. First insulation 6122 may inhibit or decrease coking inconduit 6128 when a carbon containing fuel is in conduit 6128. Firstinsulation 6122 may be made of a non-corrosive, thermally insulatingmaterial such as rock wool, Nextel®, calcium silicate, Fiberfrax®,insulating refractory cements such as those manufactured by HarbizonWalker, A. P. Green, or National Refractories, etc. The relatively hightemperatures generated at the flame of first oxidizer 6120, which may beabout 1300° C. or greater, may generate sufficient heat to converthydrocarbons proximate the first oxidizer into coke and/or char if noinsulation is provided.

[1069] Heated fluids from conduit 6110 may exit a lower end of theconduit into opening 514. A temperature of the heated fluids may belower proximate the lower end of conduit 6110 than a temperature of theheated fluids proximate first oxidizer 6120. The heated fluids mayreturn to a surface of the formation through the annulus of opening 514(exhaust annulus 6124) and/or through exhaust conduit 6126. The heatedfluids exiting the formation through exhaust conduit 6126 may bereferred to as exhaust fluids. The exhaust fluids may be allowed tothermally contact conduit 6110 so as to exchange heat between exhaustfluids and either oxidizing fluid or fuel within conduit 6110. Thisexchange of heat may preheat fluids within conduit 6110. Thus, thethermal efficiency of the downhole combustor may be enhanced to as muchas 90% or more (i.e., 90% or more of the heat from the heat ofcombustion is being transferred to a selected section of the formation).

[1070] In certain embodiments, extra oxidizers may be used in additionto oxidizer 6120 and oxidizer 6130 shown in FIG. 97. For example, insome embodiments, one or more extra oxidizers may be placed betweenoxidizer 6120 and oxidizer 6130. Such extra oxidizers may be, forexample, placed at intervals of about 20-50 m. In certain embodiments,one oxidizer (e.g., oxidizer 6120) may provide at least about 50% of theheat to the selected section of the formation, and the other oxidizersmay be used to adjust the heat flux along the length of the oxidizer.

[1071] In some embodiments, fins may be placed on an outside surface ofconduit 6110 to increase exchange of heat between exhaust fluids andfluids within the conduit. Exhaust conduit 6126 may extend into opening514. A position of lower end of exhaust conduit 6126 may vary dependingon, for example, a desired removal rate of exhaust fluids from theopening. In certain embodiments, it may be advantageous to remove fluidsthrough exhaust conduit 6126 from a lower portion of opening 514 ratherthan allowing exhaust fluids to return to the surface through theannulus of the opening. All or part of the exhaust fluids may be vented,treated in a surface facility, and/or recycled. In some circumstances,the exhaust fluids may be recycled as a portion of fuel 6118 oroxidizing fluid 517 or recycled into an additional heater in anotherportion of the formation.

[1072] Two or more heater wells with oxidizers may be coupled in serieswith exhaust fluids from a first heater well being used as a portion offuel for a second heater well. Exhaust fluids from the second heaterwell may be used as a portion of fuel for a third heater well, and so onas needed. In some embodiments, a separator may separate unused fueland/or oxidizer from combustion products to increase the energy contentof the fuel for the next oxidizer. Using the heated exhaust fluids as aportion of the feed for a heater well may decrease costs associated withpressurizing fluids for use in the heater well. In an embodiment, aportion (e.g., about one-third or about one-half) of the oxygen in theoxidizing fluid stream provided to a first heater well may be utilizedin the first heater well. This would leave the remaining oxygenavailable for use as oxidizing fluid for subsequent heater wells. Theheated exhaust fluids tend to have a pressure associated with theprevious heater well and may be maintained at that pressure forproviding to the next heater well. Thus, connection of two or moreheater wells in series can significantly reduce compression costsassociated with pressurizing fluids.

[1073] Casing 541 and reinforcing material 544 may be placed inoverburden 540. Overburden 540 may be above hydrocarbon layer 6100. Incertain embodiments, casing 541 may extend downward into part or theentire zone being heated. Casing 541 may include steel (e.g., carbonsteel or stainless steel). Reinforcing material 544 may include, forexample, foamed cement or a cement with glass and/or ceramic beadsfilled with air.

[1074] As depicted in the embodiment of FIG. 97, a heater may havesecond fuel conduit 6128. Second fuel conduit 6128 may be coupled toconduit 6110. Second fuel source 6121 may provide fuel 6118 to secondfuel conduit 6128. Second fuel source 6121 may provide fuel that issimilar to fuel from first fuel source 6119. In some embodiments, fuelfrom second fuel source 6121 may be different than fuel from first fuelsource 6119. Fuel 6118 may exit second fuel conduit 6128 at a locationproximate second oxidizer 6130. Second oxidizer 6130 may be locatedproximate a bottom of conduit 6110 and/or opening 514. Second oxidizer6130 may be coupled to a lower end of second fuel conduit 6128. Secondoxidizer 6130 may be used to oxidize at least a portion of fuel 6118(exiting second fuel conduit 6128) with heated fluids exiting conduit6110. Un-oxidized portions of heated fluids from conduit 6110 may alsobe oxidized at second oxidizer 6130. Second oxidizer 6130 may be aburner (e.g., a ring burner). Second oxidizer 6130 may be made ofstainless steel. Second oxidizer 6130 may include one or more orificesthat allow a flow of fuel 6118 into opening 514. The one or moreorifices may be critical flow orifices. Oxidized portions of fuel 6118,along with un-oxidized portions of fuel, may combine with heated fluidsfrom conduit 6110 and exit the formation with the heated fluids. Heatgenerated by oxidation of fuel 6118 from second fuel conduit 6128proximate a lower end of opening 514, in combination with heat generatedfrom heated fluids in conduit 6110, may provide more uniform heating ofhydrocarbon layer 6100 than using a single oxidizer. In an embodiment,second oxidizer 6130 may be located about 200 m from first oxidizer6120. However, in some embodiments, second oxidizer 6130 may be locatedup to about 250 m from first oxidizer 6120.

[1075] Heat generated by oxidation of fuel at the first and secondoxidizers may be allowed to transfer to the formation. The generatedheat may transfer to a pyrolysis zone in the formation. Heat transferredto the pyrolysis zone may pyrolyze at least some hydrocarbons within thepyrolysis zone.

[1076] In some embodiments, ignition source 6134 may be disposedproximate a lower end of second fuel conduit 6128 and/or second oxidizer6130. Ignition source 6134 may be an electrically controlled ignitionsource. Ignition source 6134 may be coupled to ignition source lead-inwire 6136. Ignition source lead-in wire 6136 may be further coupled to apower source for ignition source 6134. Ignition source 6134 may be usedto initiate oxidation of fuel 6118 exiting second fuel conduit 6128.After oxidation of fuel 6118 from second fuel conduit 6128 has begun,ignition source 6134 may be turned down and/or off. In otherembodiments, an ignition source may also be disposed proximate firstoxidizer 6120.

[1077] In some embodiments, ignition source 6134 may not be used if, forexample, the conditions in the wellbore are sufficient to auto-ignitefuel 6118 being used. For example, if hydrogen is used as the fuel, thehydrogen will auto-ignite in the wellbore if the temperature andpressure in the wellbore are sufficient for autoignition of the fuel.

[1078] As shown in FIG. 97, second insulation 6132 may be disposed in aregion proximate second oxidizer 6130. Second insulation 6132 may bedisposed on a face of hydrocarbon layer 6100 along an inner surface ofopening 514. Second insulation 6132 may have a length of about 10 m toabout 200 m (e.g., about 50 m). A length of second insulation 6132 mayvary, however, depending on, for example, a desired heat transfer rateto the formation, a desired temperature proximate the lower oxidizer, ora desired temperature profile along a length of conduit 6110 and/orhydrocarbon layer 6100. In an embodiment, the length of secondinsulation 6132 is about 10-40% of the length of conduit 6110 betweenany two oxidizers. Second insulation 6132 may have a thickness thatvaries (either continually or in step fashion) along its length. Incertain embodiments, second insulation 6132 may have a larger thicknessproximate second oxidizer 6130 and a reduced thickness at a desireddistance from the second oxidizer. The larger thickness of secondinsulation 6132 may preferentially reduce heat transfer proximate secondoxidizer 6130 as compared to the reduced thickness portion of theinsulation. For example, second insulation 6132 may have a thickness ofabout 0.03 m proximate second oxidizer 6130 and a thickness of about0.015 m at a distance of about 10 m from the second oxidizer.

[1079] A thickness of second insulation 6132 may vary depending on, forexample, a desired heating rate or a desired temperature at a surface ofhydrocarbon layer 6100. The second insulation may inhibit the transferof heat from the heated fluids to the formation in a region proximatethe insulation. Second insulation 6132 may also inhibit charring and/orcoking of hydrocarbons proximate second oxidizer 6130. Second insulation6132 may inhibit charring and/or coking by reducing an amount of heattransferred to the formation proximate the second oxidizer. Secondinsulation 6132 may be made of a non-corrosive, thermally insulatingmaterial such as rock wool, Nextel™, calcium silicate, Fiberfrax®, orthermally insulating concretes such as those manufactured by HarbizonWalker, A. P. Green, or National Refractories. Hydrogen and/or steam mayalso be added to fuel used in the second oxidizer to further inhibitcoking and/or charring of the formation proximate the second oxidizerand/or fuel within the fuel conduit.

[1080] In other embodiments, one or more additional oxidizers may beplaced in opening 514. The one or more additional oxidizers may be usedto increase a heat output and/or provide more uniform heating of theformation. Additional fuel conduits and/or additional insulatingconduits may be used with the one or more additional oxidizers asneeded.

[1081] In an example using two downhole combustors to heat a portion ofa formation, the formation has a depth for treatment of about 228 m,with an overburden having a depth of about 91.5 m. Two oxidizers areused, as shown in the embodiment of FIG. 97, to provide heat to theformation in an opening with a diameter of about 0.15 m. To equalize thepressure inside the conduit and outside the conduit, a cross-sectionalarea inside the conduit should approximately equal a cross-sectionalarea outside the conduit. Thus, the conduit has a diameter of about 0.11m.

[1082] To heat the formation at a heat input of about 655 watts/meter(W/m), a total heat input of about 150,000 W is needed. About 16,000 Wof heat is generated for every 28 standard liters per minute (slm) ofmethane (CH₄) provided to the burners. Thus, a flow rate of about 270slm is needed to generate the 150,000 W of heat. A temperature midwaybetween the two oxidizers is about 555° C. less than the temperature ata flame of either oxidizer (about 1315° C.). The temperature midwaybetween the two oxidizers on the wall of the formation (where there isno insulation) is about 690° C. About 3,800 W can be carried by 2,830slm of air for every 55° C. of temperature change in the conduit. Thus,for the air to carry half the heat required (about 75,000 W) from thefirst oxidizer to the halfway point, 5,660 slm of air is needed. Theother half of the heat required may be supplied by air passing thesecond oxidizer and carrying heat from the second oxidizer.

[1083] Using air (21% oxygen) as the oxidizing fluid, a flow rate ofabout 5,660 slm of air can be used to provide excess oxygen to eachoxidizer. About half of the oxygen, or about 11% of the air, is used inthe two oxidizers in a first heater well. Thus, the exhaust fluid isessentially air with an oxygen content of about 10%. This exhaust fluidcan be used in a second heater well. Pressure of the incoming air of thefirst heater well is about 6.2 bars absolute. Pressure of the outgoingair of the first heater well is about 4.4 bars absolute. This pressureis also the incoming air pressure of a second heater well. The outletpressure of the second heater well is about 1.7 bars absolute. Thus, theair does not need to be recompressed between the first heater well andthe second heater well.

[1084]FIG. 98 illustrates a cross-sectional representation of anembodiment of a downhole combustor heater for heating a formation. Asdepicted in FIG. 98, electric heater 6140 may be used instead of secondoxidizer 6130 (as shown in FIG. 97) to provide additional heat to aportion of hydrocarbon layer 6100.

[1085] In a heat source embodiment, electric heater 6140 may be aninsulated conductor heater. In some embodiments, electric heater 6140may be a conductor-in-conduit heater or an elongated member heater. Ingeneral, electric heaters tend to provide a more controllable and/orpredictable heating profile than combustion heaters. The heat profile ofelectric heater 6140 may be selected to achieve a selected heatingprofile of the formation (e.g., uniform). For example, the heatingprofile of electric heater 6140 may be selected to “mirror” the heatingprofile of oxidizer 6120 such that, when the heat from electric heater6140 and oxidizer 6120 are superpositioned, substantially uniformheating is applied along the length of the conduit.

[1086] In other heat source embodiments, any other type of heater, suchas a natural distributed combustor or flameless distributed combustor,may be used instead of electric heater 6140. In certain embodiments,electric heater 6140 may be used instead of first oxidizer 6120 to heata portion of hydrocarbon layer 6100. FIG. 99 depicts an embodiment usinga downhole combustor with a flameless distributed combustor. Second fuelconduit 6128 may have orifices 515 (e.g., critical flow orifices)distributed along the length of the conduit. Orifices 515 may bedistributed such that a heating profile along the length of hydrocarbonlayer 6100 is substantially uniform. For example, more orifices 515 maybe placed on second fuel conduit 6128 in a lower portion of the conduitthan in an upper portion of the conduit. This will provide more heatingto a portion of hydrocarbon layer 6100 that is farther from firstoxidizer 6120.

[1087] As depicted in FIG. 98, electric heater 6140 may be placed inopening 514 proximate conduit 6110. Electric heater 6140 may be used toprovide heat to hydrocarbon layer 6100 in a portion of opening 514proximate a lower end of conduit 6110. Electric heater 6140 may becoupled to lead-in conductor 6142. Using electric heater 6140 as well asheated fluids from conduit 6110 to heat hydrocarbon layer 6100 mayprovide substantially uniform heating of hydrocarbon layer 6100.

[1088]FIG. 100 illustrates a cross-sectional representation of anembodiment of a multilateral downhole combustor heater. Hydrocarbonlayer 6100 may be a relatively thin layer (e.g., with a thickness ofless than about 10 m, about 30 m, or about 60 m) selected for treatment.Such layers may exist in oil shale. Opening 514 may extend belowoverburden 540 and then diverge in more than one direction withinhydrocarbon layer 6100. Opening 514 may have walls that aresubstantially parallel to upper and lower surfaces of hydrocarbon layer6100.

[1089] Conduit 6110 may extend substantially vertically into opening 514as depicted in FIG. 100. First oxidizer 6120 may be placed in orproximate conduit 6110. Oxidizing fluid 517 may be provided to firstoxidizer 6120 through conduit 6110. First fuel conduit 6116 may be usedto provide fuel 6118 to first oxidizer 6120. Second conduit 6150 may becoupled to conduit 6110. Second conduit 6150 may be orientedsubstantially perpendicular to conduit 6110. Third conduit 6148 may alsobe coupled to conduit 6110. Third conduit 6148 may be orientedsubstantially perpendicular to conduit 6110. Second oxidizer 6130 may beplaced at an end of second conduit 6150. Second oxidizer 6130 may be aring burner. Third oxidizer 6144 may be placed at an end of thirdconduit 6148. In an embodiment, third oxidizer 6144 is a ring burner.Second oxidizer 6130 and third oxidizer 6144 may be placed at or nearopposite ends of opening 514.

[1090] Second fuel conduit 6128 may be used to provide fuel to secondoxidizer 6130. Third fuel conduit 6138 may be used to provide fuel tothird oxidizer 6144. Oxidizing fluid 517 may be provided to secondoxidizer 6130 through conduit 6110 and second conduit 6150. Oxidizingfluid 517 may be provided to third oxidizer 6144 through conduit 6110and third conduit 6148. First insulation 6122 may be placed proximatefirst oxidizer 6120. Second insulation 6132 and third insulation 6146may be placed proximate second oxidizer 6130 and third oxidizer 6144,respectively. Second oxidizer 6130 and third oxidizer 6144 may belocated up to about 175 m from first conduit 6110. In some embodiments,a distance between second oxidizer 6130 or third oxidizer 6144 and firstconduit 6110 may be less, depending on heating requirements ofhydrocarbon layer 6100. Heat provided by oxidation of fuel at firstoxidizer 6120, second oxidizer 6130, and third oxidizer 6144 may allowfor substantially uniform heating of hydrocarbon layer 6100.

[1091] Exhaust fluids may be removed through opening 514. The exhaustfluids may exchange heat with fluids entering opening 514 throughconduit 6110. Exhaust fluids may also be used in additional heater wellsand/or treated in surface facilities.

[1092] In a heat source embodiment, one or more electric heaters may beused instead of, or in combination with, first oxidizer 6120, secondoxidizer 6130, and/or third oxidizer 6144 to provide heat to hydrocarbonlayer 6100. Using electric heaters in combination with oxidizers mayprovide for substantially uniform heating of hydrocarbon layer 6100.

[1093]FIG. 101 depicts a heat source embodiment in which one or moreoxidizers are placed in first conduit 6160 and second conduit 6162 toprovide heat to hydrocarbon layer 6100. The embodiment may be used toheat a relatively thin formation. First oxidizer 6120 may be placed infirst conduit 6160. A second oxidizer 6130 may be placed proximate anend of first conduit 6160. First fuel conduit 6116 may provide fuel tofirst oxidizer 6120. Second fuel conduit 6128 may provide fuel to secondoxidizer 6130. First insulation 6122 may be placed proximate firstoxidizer 6120. Oxidizing fluid 517 may be provided into first conduit6160. A portion of oxidizing fluid 517 may be used to oxidize fuel atfirst oxidizer 6120. Second insulation may be placed proximate secondoxidizer 6130.

[1094] Second conduit 6162 may diverge in an opposite direction fromfirst conduit 6160 in opening 514 and substantially mirror first conduit6160. Second conduit 6162 may include elements similar to the elementsof first conduit 6160, such as first oxidizer 6120, first fuel conduit6116, first insulation 6122, second oxidizer 6130, second fuel conduit6128, and/or second insulation 6132. These elements may be used tosubstantially uniformly heat hydrocarbon layer 6100 below overburden 540along lengths of conduits 6160 and 6162.

[1095]FIG. 102 illustrates a cross-sectional representation of anembodiment of a downhole combustor for heating a formation. Opening 514is a single opening within hydrocarbon layer 6100 that may have firstend 6170 and second end 6172. Oxidizers 6120 may be placed in opening514 proximate a junction of overburden 540 and hydrocarbon layer 6100 atfirst end 6170 and second end 6172. Insulation 6132 may be placedproximate each oxidizer 6120. Fuel conduit 6116 may be used to providefuel 6118 from fuel source 6119 to oxidizer 6120. Oxidizing fluid 517may be provided into opening 514 from oxidizing fluid source 508 throughconduit 6110. Casing 6152 may be placed in opening 514. Casing 6152 maybe made of carbon steel. Portions of casing 6152 that may be subjectedto much higher temperatures (e.g., proximate oxidizers 6120) may includestainless steel or other high temperature, corrosion resistant metal. Insome embodiments, casing 6152 may extend into portions of opening 514within overburden 540.

[1096] In a heat source embodiment, oxidizing fluid 517 and fuel 6118are provided to oxidizer 6120 in first end 6170. Heated fluids fromoxidizer 6120 in first end 6170 tend to flow through opening 514 towardssecond end 6172. Heat may transfer from the heated fluids to hydrocarbonlayer 6100 along a length of opening 514. The heated fluids may beremoved from the formation through second end 6172. During this time,oxidizer 6120 at second end 6172 may be turned off. The removed fluidsmay be provided to a second opening in the formation and used asoxidizing fluid and/or fuel in the second opening. After a selected time(e.g., about a week), oxidizer 6120 at first end 6170 may be turned off.At this time, oxidizing fluid 517 and fuel 6118 may be provided tooxidizer 6120 at second end 6172 and the oxidizer turned on. Heatedfluids may be removed during this time through first end 6170. Oxidizers6120 at first end 6170 and at second end 6172 may be used alternatelyfor selected times (e.g., about a week) to heat hydrocarbon layer 6100.This may provide a more substantially uniform heating profile ofhydrocarbon layer 6100. Removing the heated fluids from the openingthrough an end distant from an oxidizer may reduce a possibility ofcoking within opening 514 as heated fluids are removed from the openingseparately from incoming fluids. The use of the heat content of anoxidizing fluid may also be more efficient as the heated fluids can beused in a second opening or second downhole combustor.

[1097]FIG. 102A depicts an embodiment of a heat source for an oil shaleformation. Fuel conduit 6116 may be placed within opening 514. In someembodiments, opening 514 may include casing 6152. Opening 514 is asingle opening within the formation that may have first end 6170 at afirst location on the surface of the earth and second end 6172 at asecond location on the surface of the earth. Oxidizers 6120 may bepositioned proximate the fuel conduit in hydrocarbon layer 516.Oxidizers 6120 may be separated by a distance ranging from about 3 m toabout 50 m (e.g., about 30 m). Fuel 6118 may be provided to fuel conduit6116. In addition, steam 9674 may be provided to fuel conduit 6116 toreduce coking proximate oxidizers 6120 and/or in fuel conduit 6116.Oxidizing fluid 6110 (e.g., air and/or oxygen) may be provided tooxidizers 6120 through opening 514. Oxidation of fuel 6118 may generateheat. The heat may transfer to a portion of the formation. Oxidationproducts 9676 may exit opening 514 proximate second location 6172.

[1098]FIG. 103 depicts a schematic, from an elevated view, of anembodiment for using downhole combustors depicted in the embodiment ofFIG. 102. Openings 6180, 6182, 6184, 6186, 6188, and 6190 may havedownhole combustors (as shown in the embodiment of FIG. 102) placed ineach opening. More or fewer openings (i.e., openings with a downholecombustor) may be used as needed. A number of openings may depend on,for example, a size of an area for treatment, a desired heating rate, ora selected well spacing. Conduit 6196 may be used to transport fluidsfrom a downhole combustor in opening 6180 to downhole combustors inopenings 6182, 6184, 6186, 6188, and 6190. The openings may be coupledin series using conduit 6196. Compressor 6192 may be used betweenopenings, as needed, to increase a pressure of fluid between theopenings. Additional oxidizing fluid may be provided to each compressor6192 from conduit 6194. A selected flow of fuel from a fuel source maybe provided into each of the openings.

[1099] For a selected time, a flow of fluids may be from first opening6180 towards opening 6190. Flow of fluid within first opening 6180 maybe substantially opposite flow within second opening 6182. Subsequently,flow within second opening 6182 may be substantially opposite flowwithin third opening 6184, etc. This may provide substantially moreuniform heating of the formation using the downhole combustors withineach opening. After the selected time, the flow of fluids may bereversed to flow from opening 6190 towards first opening 6180. Thisprocess may be repeated as needed during a time needed for treatment ofthe formation. Alternating the flow of fluids may enhance the uniformityof a heating profile of the formation.

[1100]FIG. 104 depicts a schematic representation of an embodiment of aheater well positioned within an oil shale formation. Heater well 6230may be placed within opening 514. In certain embodiments, opening 514 isa single opening within the formation that may have first end 6170 andsecond end 6172 contacting the surface of the earth. Opening 514 mayinclude elongated portions 9630, 9632, 9634. Elongated portions 9630,9634 may be placed substantially in a non-hydrocarbon containing layer(e.g., overburden). Elongated portion 9632 may be placed substantiallywithin hydrocarbon layer 6100 and/or a treatment zone.

[1101] In some heat source embodiments, casing 6152 may be placed inopening 514. In some embodiments, casing 6152 may be made of carbonsteel. Portions of casing 6152 that may be subjected to hightemperatures may be made of more temperature resistant material (e.g.,stainless steel). In some embodiments, casing 6152 may extend intoelongated portions 9630, 9634 within overburden 540. Oxidizers 6120,6130 may be placed proximate a junction of overburden 540 andhydrocarbon layer 6100 at first end 6170 and second end 6172 of opening514. Oxidizers 6120, 6130 may include burners (e.g., inline burnersand/or ring burners). Insulation 6132 may be placed proximate eachoxidizer 6120, 6130.

[1102] Conduit 9620 may be placed within opening 514 forming annulus9621 between an outer surface of conduit 9620 and an inner surface ofthe casing 6152. Annulus 9621 may have a regular and/or irregular shapewithin the opening. In some embodiments, oxidizers may be positionedwithin the annulus and/or the conduit to provide heat to a portion ofthe formation. Oxidizer 6120 is positioned within annulus 9621 and mayinclude a ring burner. Heated fluids from oxidizer 6120 may flow withinannulus 9621 to end 6172. Heated fluids from oxidizer 6130 may bedirected by conduit 9620 through opening 514. Heated fluids may include,but are not limited to oxidation products, oxidizing fluid, and/or fuel.Flow of the heated fluids through annulus 9621 may be in the oppositedirection of the flow of heated fluids in conduit 9620. In alternateembodiments, oxidizers 6120, 6130 may be positioned proximate the sameend of opening 514 to allow the heated fluids to flow through opening514 in the same direction.

[1103] Fuel conduits 6116 may be used to provide fuel 6118 from fuelsource 6119 to oxidizers 6120, 6130. Oxidizing fluid 517 may be providedto oxidizers 6120, 6130 from oxidizing fluid source 508 through conduits6110. Flow of fuel 6118 and oxidizing fluid 517 may generate oxidationproducts at oxidizers 6120, 6130. In some embodiments, a flow ofoxidizing fluid 517 may be controlled to control oxidation at oxidizers6120, 6130. Alternatively, a flow of fuel may be controlled to controloxidation at oxidizers 6120, 6130.

[1104] In a heat source embodiment, oxidizing fluid 517 and fuel 6118are provided to oxidizer 6120. Heated fluids from oxidizer 6120 in firstend 6170 tend to flow through opening 514 towards second end 6172. Heatmay transfer from the heated fluids to hydrocarbon layer 6100 along asegment of opening 514. The heated fluids may be removed from theformation through second end 6172. In some embodiments, a portion of theheated fluids removed from the formation may be provided to fuel conduit6116 at end 6172 to be utilized as fuel in oxidizer 6130. Fluids heatedby oxidizer 6130 may be directed through the opening in conduit 9620 tofirst end 6170. In some embodiments, a portion of the heated fluids isprovided to fuel conduit 6116 at first end 6170. Alternatively, heatedfluids produced from either end of the opening may be directed to asecond opening in the formation for use as either oxidizing fluid and/orfuel. In some embodiments, heated fluids may be directed toward one endof the opening for use in a single oxidizer.

[1105] Oxidizers 6120, 6130 may be utilized concurrently. In someembodiments, use of the oxidizers may alternate. Oxidizer 6120 may beturned off after a selected time period (e.g., about a week). At thistime, oxidizing fluid 517 and fuel 6118 may be provided to oxidizer6130. Heated fluids may be removed during this time through first end6170. Use of oxidizer 6120 and oxidizer 6130 may be alternated forselected times to heat hydrocarbon layer 6100. Flowing oxidizing fluidsin opposite directions may produce a more uniform heating profile inhydrocarbon layer 6100. Removing the heated fluids from the openingthrough an end distant from the oxidizer at which the heated fluids wereproduced may reduce the possibility for coking within the opening.Heated fluids may be removed from the formation in exhaust conduits insome embodiments. In addition, the potential for coking may be furtherreduced by removing heated fluids from the opening separately fromincoming fluids (e.g., fuel and/or oxidizing fluid). In certaininstances, some heat within the heated fluids may transfer to theincoming fluids to increase the efficiency of the oxidizers.

[1106]FIG. 105 depicts an embodiment of a heat source positioned withinan oil shale formation. Surface units 9672 (e.g., burners and/orfurnaces) provide heat to an opening in the formation. Surface unit 9672may provide heat to conduit 9620 positioned in conduit 9622. Surfaceunit 9672 positioned proximate first end 6170 of opening 514 may heatfluids 9670 (e.g., air, oxygen, steam, fuel, and/or flue gas) providedto surface unit 9672. Conduit 9620 may extend into surface unit 9672 toallow fluids heated in surface unit 9672 proximate first end 6170 toflow into conduit 9620. Conduit 9620 may direct fluid flow to second end6172. At second end 6172 conduit 9620 may provide fluids to surface unit9672. Surface unit 9672 may heat the fluids. The heated fluids may flowinto conduit 9622. Heated fluids may then flow through conduit 9622towards end 6170. In some embodiments, conduit 9620 and conduit 9622 maybe concentric.

[1107] In alternate embodiments, fluids may be compressed prior toentering the surface unit. Compression of the fluids may maintain afluid flow through the opening. Flow of fluids through the conduits mayaffect the transfer of heat from the conduits to the formation.

[1108] In alternate embodiments, a single surface unit may be utilizedfor heating proximate first end 6170. Conduits may be positioned suchthat fluid within an inner conduit flows into the annulus between theinner conduit and an outer conduit. Thus the fluid flow in the innerconduit and the annulus may be counter current.

[1109] A heat source embodiment is illustrated in FIG. 106. Conduits9620, 9622 may be placed within opening 514. Opening 514 may be an openwellbore. In alternate embodiments, a casing may be included in aportion of the opening (e.g., in the portion in the overburden). Inaddition, some embodiments may include insulation surrounding a portionof conduits 9620, 9622. For example, the portions of the conduits withinoverburden 540 may be insulated to inhibit heat transfer from the heatedfluids to the overburden and/or a portion of the formation proximate theoxidizers.

[1110]FIG. 107 illustrates an embodiment of a surface combustor that mayheat a section of an oil shale formation. Fuel fluid 611 may be providedinto burner 610 through conduit 617. An oxidizing fluid may be providedinto burner 610 from oxidizing fluid source 508. Fuel fluid 611 may beoxidized with the oxidizing fluid in burner 610 to form oxidationproducts 613. Fuel fluid 611 may include, but is not limited to,hydrogen, methane, ethane, and/or other hydrocarbons. Burner 610 may belocated external to the formation or within opening 614 in hydrocarbonlayer 516. Source 618 may heat fuel fluid 611 to a temperaturesufficient to support oxidation in burner 610. Source 618 may heat fuelfluid 611 to a temperature of about 1425° C. Source 618 may be coupledto an end of conduit 617. In a heat source embodiment, source 618 is apilot flame. The pilot flame may burn with a small flow of fuel fluid611. In other embodiments, source 618 may be an electrical ignitionsource.

[1111] Oxidation products 613 may be provided into opening 614 withininner conduit 612 coupled to burner 610. Heat may be transferred fromoxidation products 613 through outer conduit 615 into opening 614 and tohydrocarbon layer 516 along a length of inner conduit 612. Oxidationproducts 613 may cool along the length of inner conduit 612. Forexample, oxidation products 613 may have a temperature of about 870° C.proximate top of inner conduit 612 and a temperature of about 650° C.proximate bottom of inner conduit 612. A section of inner conduit 612proximate burner 610 may have ceramic insulator 612 b disposed on aninner surface of inner conduit 612. Ceramic insulator 612 b may inhibitmelting of inner conduit 612 and/or insulation 612 a proximate burner610. Opening 614 may extend into the formation a length up to about 550m below surface 550.

[1112] Inner conduit 612 may provide oxidation products 613 into outerconduit 615 proximate a bottom of opening 614. Inner conduit 612 mayhave insulation 612 a. FIG. 108 illustrates an embodiment of innerconduit 612 with insulation 612 a and ceramic insulator 612 b disposedon an inner surface of inner conduit 612. Insulation 612 a may inhibitheat transfer between fluids in inner conduit 612 and fluids in outerconduit 615. A thickness of insulation 612 a may be varied along alength of inner conduit 612 such that heat transfer to hydrocarbon layer516 may vary along the length of inner conduit 612. For example, athickness of insulation 612 a may be tapered from a larger thickness toa lesser thickness from a top portion to a bottom portion, respectively,of inner conduit 612 in opening 614. Such a tapered thickness mayprovide more uniform heating of hydrocarbon layer 516 along the lengthof inner conduit 612 in opening 614. Insulation 612 a may includeceramic and metal materials. Oxidation products 613 may return tosurface 550 through outer conduit 615. Outer conduit may have insulation615 a, as depicted in FIG. 107. Insulation 615 a may inhibit heattransfer from outer conduit 615 to overburden 540.

[1113] Oxidation products 613 may be provided to an additional burnerthrough conduit 619 at surface 550. Oxidation products 613 may be usedas a portion of a fuel fluid in the additional burner. Doing so mayincrease an efficiency of energy output versus energy input for heatinghydrocarbon layer 516. The additional burner may provide heat through anadditional opening in hydrocarbon layer 516.

[1114] In some embodiments, an electric heater may provide heat inaddition to heat provided from a surface combustor. The electric heatermay be, for example, an insulated conductor heater or aconductor-in-conduit heater as described in any of the aboveembodiments. The electric heater may provide the additional heat to anoil shale formation so that the oil shale formation is heatedsubstantially uniformly along a depth of an opening in the formation.

[1115] Flameless combustors such as those described in U.S. Pat. No.5,404,952 to Vinegar et al., which is incorporated by reference as iffully set forth herein, may heat an oil shale formation.

[1116]FIG. 109 illustrates an embodiment of a flameless combustor thatmay heat a section of the oil shale formation. The flameless combustormay include center tube 637 disposed within inner conduit 638. Centertube 637 and inner conduit 638 may be placed within outer conduit 636.Outer conduit 636 may be disposed within opening 514 in hydrocarbonlayer 516. Fuel fluid 621 may be provided into the flameless combustorthrough center tube 637. If a hydrocarbon fuel such as methane isutilized, the fuel may be mixed with steam to inhibit coking in centertube 637. If hydrogen is used as the fuel, no steam may be required.

[1117] Center tube 637 may include flow mechanisms 635 (e.g., floworifices) disposed within an oxidation region to allow a flow of fuelfluid 621 into inner conduit 638. Flow mechanisms 635 may control a flowof fuel fluid 621 into inner conduit 638 such that the flow of fuelfluid 621 is not dependent on a pressure in inner conduit 638. Oxidizingfluid 623 may be provided into the combustor through inner conduit 638.Oxidizing fluid 623 may be provided from oxidizing fluid source 508.Flow mechanisms 635 on center tube 637 may inhibit flow of oxidizingfluid 623 into center tube 637.

[1118] Oxidizing fluid 623 may mix with fuel fluid 621 in the oxidationregion of inner conduit 638. Either oxidizing fluid 623 or fuel fluid621, or a combination of both, may be preheated external to thecombustor to a temperature sufficient to support oxidation of fuel fluid621. Oxidation of fuel fluid 621 may provide heat generation withinouter conduit 636. The generated heat may provide heat to a portion ofan oil shale formation proximate the oxidation region of inner conduit638. Products 625 from oxidation of fuel fluid 621 may be removedthrough outer conduit 636 outside inner conduit 638. Heat exchangebetween the downgoing oxidizing fluid and the upgoing combustionproducts in the overburden results in enhanced thermal efficiency. Aflow of removed combustion products 625 may be balanced with a flow offuel fluid 621 and oxidizing fluid 623 to maintain a temperature aboveauto-ignition temperature but below a temperature sufficient to produceoxides of nitrogen. In addition, a constant flow of fluids may provide asubstantially uniform temperature distribution within the oxidationregion of inner conduit 638. Outer conduit 636 may be a stainless steeltube. Heating in the portion of the oil shale formation may besubstantially uniform. Maintaining a temperature below temperaturessufficient to produce oxides of nitrogen may allow for relativelyinexpensive metallurgical cost.

[1119] Care may be taken during design and installation of a well (e.g.,freeze wells, production wells, monitoring wells, and heat sources) intoa formation to allow for thermal effects within the formation. Heatingand/or cooling of the formation may expand and/or contract elements of awell, such as the well casing. Elements of a well may expand or contractat different rates (e.g., due to different thermal expansioncoefficients). Thermal expansion or contraction may cause failures (suchas leaks, fractures, short-circuiting, etc.) to occur in a well. Anoperational lifetime of one or more elements in the wellbore may beshortened by such failures.

[1120] In some well embodiments, a portion of the well is an openwellbore completion. Portions of the well may be suspended from awellbore or a casing that is cemented in the formation (e.g., a portionof a well in the overburden). Expansion of the well due to heat may beaccommodated in the open wellbore portion of the well.

[1121] In a well embodiment, an expansion mechanism may be coupled to aheat source or other element of a well placed in an opening in aformation. The expansion mechanism may allow for thermal expansion ofthe heat source or element during use. The expansion mechanism may beused to absorb changes in length of the well as the well expands orcontracts with temperature. The expansion mechanism may inhibit the heatsource or element from being pushed out of the opening during thermalexpansion. Using the expansion mechanism in the opening may increase anoperational lifetime of the well.

[1122]FIG. 110 illustrates a representation of an embodiment ofexpansion mechanism 6012 coupled to heat source 8682 in opening 514 inhydrocarbon layer 516. Expansion mechanism 6012 may allow for thermalexpansion of heat source 8682. Heat source 8682 may be any heat source(e.g., conductor-in-conduit heat source, insulated conductor heatsource, natural distributed combustor heat source, etc.). In someembodiments, more than one expansion mechanism 6012 may be coupled toindividual components of a heat source. For example, if the heat sourceincludes more than one element (e.g., conductors, conduits, supports,cables, elongated members, etc.), an expansion mechanism may be coupledto each element. Expansion mechanism 6012 may include spring loading. Inone embodiment, expansion mechanism 6012 is an accordion mechanism. Inanother embodiment, expansion mechanism 6012 is a bellows or anexpansion joint.

[1123] Expansion mechanism 6012 may be coupled to heat source 8682 at abottom of the heat source in opening 514. In some embodiments, expansionmechanism 6012 may be coupled to heat source 8682 at a top of the heatsource. In other embodiments, expansion mechanism 6012 may be placed atany point along the length of heat source 8682 (e.g., in a middle of theheat source). Expansion mechanism 6012 may be used to reduce the hangingweight of heat source 8682 (i.e., the weight supported by a wellheadcoupled to the heat source). Reducing the hanging weight of heat source8682 may reduce creeping of the heat source during heating.

[1124] Certain heat source embodiments may include an operating systemcoupled to a heat source or heat sources by insulated conductors orother types of wiring. The operating system may interface with the heatsource. The operating system may receive a signal (e.g., anelectromagnetic signal) from a heater that is representative of atemperature distribution of the heat source. Additionally, the operatingsystem may control the heat source, either locally or remotely. Forexample, the operating system may alter a temperature of the heat sourceby altering a parameter of equipment coupled to the heat source. Theoperating system may monitor, alter, and/or control the heating of atleast a portion of the formation.

[1125] For some heat source embodiments, a heat source or heat sourcesmay operate without a control and/or operating system. A heat source mayonly require a power supply from a power source such as an electrictransformer. A conductor-in-conduit heater and/or an elongated memberheater may include a heater element formed of a self-regulatingmaterial, such as 304 stainless steel or 316 stainless steel. Powerdissipation and amperage through a heater element made of aself-regulating material decrease as temperature increases, and increaseas temperature decreases due in part to the resistivity properties ofthe material and Ohm's Law. For a substantially constant voltage supplyto a heater element, if the temperature of the heater element increases,the resistance of the element will increase, the amperage through theheater element will decrease, and the power dissipation will decrease;thus forcing the heater element temperature to decrease. On the otherhand, if the temperature of the heater element decreases, the resistanceof the element will decrease, the amperage through the heater elementwill increase, and the power dissipation will increase; thus forcing theheater element temperature to increase. Some metals, such as certaintypes of nichrome, have resistivity curves that decrease with increasingtemperature for certain temperature ranges. Such materials may not becapable of being self-regulating heaters.

[1126] In some heat source embodiments, leakage current of electricheaters may be monitored. For insulated heaters, an increase in leakagecurrent may show deterioration in an insulated conductor heater. Voltagebreakdown in the insulated conductor heater may cause failure of theheat source. In some heat source embodiments, a current and voltageapplied to electric heaters may be monitored. The current and voltagemay be monitored to assess/indicate resistance in a heater element ofthe heat source. The resistance in the heat source may represent atemperature in the heat source since the resistance of the heat sourcemay be known as a function of temperature. In some embodiments, atemperature of a heat source may be monitored with one or morethermocouples placed in or proximate the heat source. In someembodiments, a control system may monitor a parameter of the heatsource. The control system may alter parameters of the heat source toestablish a desired output such as heating rate and/or temperatureincrease.

[1127] In some embodiments, a thermowell may be disposed into an openingin an oil shale formation that includes a heat source. The thermowellmay be disposed in an opening that may or may not have a casing. In theopening without a casing, the thermowell may include appropriatemetallurgy and thickness such that corrosion of the thermowell isinhibited. A thermowell and temperature logging process, such as thatdescribed in U.S. Pat. No. 4,616,705 issued to Stegemeier et al., whichis incorporated by reference as if fully set forth herein, may be usedto monitor temperature. Only selected wells may be equipped withthermowells to avoid expenses associated with installing and operatingtemperature monitors at each heat source. Some thermowells may be placedmidway between two heat sources. Some thermowells may be placed at orclose to a center of a well pattern. Some thermowells may be placed inor adjacent to production wells.

[1128] In an embodiment for treating an oil shale formation in situ, anaverage temperature within a majority of a selected section of theformation may be assessed by measuring temperature within a wellbore orwellbores. The wellbore may be a production well, heater well, ormonitoring well. The temperature within a wellbore may be measured tomonitor and/or determine operating conditions within the selectedsection of the formation. The measured temperature may be used as aproperty for input into a program for controlling production within theformation. In certain embodiments, a measured temperature may be used asinput for a software executable on a computational system. In someembodiments, a temperature within a wellbore may be measured using amoveable thermocouple. The moveable thermocouple may be disposed in aconduit of a heater or heater well. An example of a moveablethermocouple and its use is described in U.S. Pat. No. 4,616,705 toStegemeier et al.

[1129] In an alternate embodiment, more than one thermocouple may beplaced in a wellbore to measure the temperature within the wellbore. Thethermocouples may be part of a multiple thermocouple array. Thethermocouples may be located at various depths and/or locations. Themultiple thermocouple array may include a magnesium oxide insulatedsheath or sheaths placed around portions of the thermocouples. Theinsulated sheaths may include corrosion resistant materials. A corrosionresistant material may include, but is not limited to, stainless steels304, 310, 316 or Inconel. Multiple thermocouple arrays may be obtainedfrom Pyrotenax Cables Ltd. (Ontario, Canada) or Idaho Labs (Idaho Falls,Id.). The multiple thermocouple array may be moveable within thewellbore.

[1130] In certain thermocouple embodiments, voltage isolation may beused with a moveable thermocouple placed in a wellbore. FIG. 111illustrates a schematic of thermocouple 9202 placed inside conductor580. Conductor 580 may be placed within conduit 582 of aconductor-in-conduit heat source. Conductor 580 may be coupled to lowresistance section 584. Low resistance section 584 may be placed inoverburden 540. Conduit 582 may be placed in wellbore 9206. Thermocouple9202 may be used to measure a temperature within conductor 580 along alength of the conductor in hydrocarbon layer 516. Thermocouple 9202 mayinclude thermocouple wires that are coupled at the surface to spool 9208so that the thermocouple is moveable along the length of conductor 580to obtain a temperature profile in the heated section. Thermocoupleisolation 9204 may be coupled to thermocouple 9202. Thermocoupleisolation 9204 may be, for example, a transformer coupled thermocoupleisolation block available from Watlow Electric Manufacturing Company(St. Louis, Mo.). Alternately, an optically isolated thermocoupleisolation block may be used. Thermocouple isolation 9204 may reducevoltages above the thermocouple isolation and at wellhead 690. Highvoltages may exist within wellbore 9206 due to use of the electric heatsource within the wellbore. The high voltages can be dangerous foroperators or personnel working around wellhead 690. With thermocoupleisolation 9204, voltages at wellhead 690 (e.g., at spool 9208) may belowered to safer levels (e.g., about zero or ground potential). Thus,using thermocouple isolation 9204 may increase safety at wellhead 690.

[1131] In some embodiments, thermocouple isolation 9204 may be usedalong the length of low resistance section 584. Temperatures within lowresistance section 584 may not be above a maximum operating temperatureof thermocouple isolation 9204. Thermocouple isolation 9204 may be movedalong the length of low resistance section 584 as thermocouple 9202 ismoved along the length of conductor 580 by spool 9208. In otherembodiments, thermocouple isolation 9204 may be placed at wellhead 690.

[1132] In a temperature monitor embodiment, a temperature within awellbore in a formation is measured using a fiber assembly. The fiberassembly may include optical fibers made from quartz or glass. The fiberassembly may have fibers surrounded by an outer shell. The fibers mayinclude fibers that transmit temperature measurement signals. A fiberthat may be used for temperature measurements can be obtained from SensaHighway (Houston, Tex.). The fiber assembly may be placed within awellbore in the formation. The wellbore may be a heater well, amonitoring well, or a production well. Use of the fibers may be limitedby a maximum temperature resistance of the outer shell, which may beabout 800° C. in some embodiments. A signal may be sent down a fiberdisposed within a wellbore. The signal may be a signal generated by alaser or other optical device. Thermal noise may be developed in thefiber from conditions within the wellbore. The amount of noise may berelated to a temperature within the wellbore. In general, the more noiseon the fiber, the higher the temperature within the wellbore. This maybe due to changes in the index of refraction of the fiber as thetemperature of the fiber changes. The relationship between noise andtemperature may be characterized for a certain fiber. This relationshipmay be used to determine a temperature of the fiber along the length ofthe fiber. The temperature of the fiber may represent a temperaturewithin the wellbore.

[1133] In some in situ conversion process embodiments, a temperaturewithin a wellbore in a formation may be measured using pressure waves. Apressure wave may include a sound wave. Examples of using sound waves tomeasure temperature are shown in U.S. Pat. Nos. 5,624,188 to West,5,437,506 to Gray, 5,349,859 to Kleppe, 4,848,924 to Nuspl et al.,4,762,425 to Shakkottai et al., and 3,595,082 to Miller, Jr., which areincorporated by reference as if fully set forth herein. Pressure wavesmay be provided into the wellbore. The wellbore may be a heater well, aproduction well, a monitoring well, or a test well. A test well may be awell placed in a formation that is used primarily for measurement ofproperties of the formation. A plurality of discontinuities may beplaced within the wellbore. A predetermined spacing may exist betweeneach discontinuity. The plurality of discontinuities may be placedinside a conduit placed within a wellbore. For example, the plurality ofdiscontinuities may be placed within a conduit used as a portion of aconductor-in-conduit heater or a conduit used to provide fluid into awellbore. The plurality of discontinuities may also be placed on anexternal surface of a conduit in a wellbore. A discontinuity mayinclude, but may not be limited to, an alumina centralizer, a stub, anode, a notch, a weld, a collar, or any such point that may reflect apressure wave.

[1134]FIG. 112 depicts a schematic view of an embodiment for usingpressure waves to measure temperature within a wellbore. Conduit 6350may be placed within wellbore 6352. Plurality of discontinuities 6354may be placed within conduit 6350. The discontinuities may be separatedby substantially constant separation distance 6356. Distance 6356 maybe, in some embodiments, about 1 m, about 5 m, or about 15 m. A pressurewave may be provided into conduit 6350 from pressure wave source 6358.Pressure wave source 6358 may include, but is not limited to, an airgun, an explosive device (e.g., blank shotgun), a piezoelectric crystal,a magnetostrictive transducer, an electrical sparker, or a compressedair source. A compressed air source may be operated or controlled by asolenoid valve. The pressure wave may propagate through conduit 6350. Insome embodiments, an acoustic wave may be propagated through the wall ofthe conduit.

[1135] A reflection (or signal) of the pressure wave within conduit 6350may be measured using wave measuring device 6363. Wave measuring device6363 may be, for example, a piezoelectric crystal, a magnetostrictivetransducer, or any device that measures a time-domain pressure of thewave within the conduit. Wave measuring device 6363 may determinetime-domain pressure wave 6360 that represents travel of the pressurewave within conduit 6350. Each slight increase in pressure, or pressurespike 6362, represents a reflection of the pressure wave at adiscontinuity 6354. The pressure wave may be repeatedly provided intothe wellbore at a selected frequency. The reflected signal may becontinuously measured to increase a signal-to-noise ratio for pressurespike 6362 in the reflected signal. This may include using a repetitivestacking of signals to reduce noise. A repeatable pressure wave sourcemay be used. For example, repeatable signals may be producible from apiezoelectric crystal. A trigger signal may be used to start wavemeasuring device 6363 and pressure wave source 6358. The time, asmeasured using pressure wave 6360, may be used with the distance betweeneach discontinuity 6356 to determine an average temperature between thediscontinuities for a known gas within conduit 6350. Since the velocityof the pressure wave varies with temperature within conduit 6350, thetime for travel of the pressure wave between discontinuities will varywith an average temperature between the discontinuities. For dry airwithin a conduit or wellbore, the temperature may be approximated usingthe equation:

c=33,145×(1+T/273.16)^(1/2);  (31)

[1136] in which c is the velocity of the wave in cm/sec and T is thetemperature in degrees Celsius. If the gas includes other gases or amixture of gases, EQN. 31 can be modified to incorporate properties ofthe alternate gas or the gas mixture. EQN. 31 can be derived from themore general equation for the velocity of a wave in a gas:

c=[(RT/M)(1+R/C _(v))]^(1/2);  (32)

[1137] in which R is the ideal gas constant, T is the temperature inKelvin, and C_(v) is the heat capacity of the gas.

[1138] Alternatively, a reference time-domain pressure wave can bedetermined at a known ambient temperature. Thus, a time-domain pressurewave determined at an increased temperature within the wellbore may becompared to the reference pressure wave to determine an averagetemperature within the wellbore after heating the formation. The changein velocity between the reference pressure wave and the increasedtemperature pressure wave, as measured by the change in distance betweenpressure spikes 6362, can be used to determine the increased temperaturewithin the conduit. Use of pressure waves to measure an averagetemperature may require relatively low maintenance. Using the velocityof pressure waves to measure temperature may be less expensive thanother temperature measurement methods.

[1139] In some embodiments, a heat source may be turned down and/or offafter an average temperature in a formation reaches a selectedtemperature. Turning down and/or off the heat source may reduce inputenergy costs, inhibit overheating of the formation, and allow heat totransfer into colder regions of the formation.

[1140] In some in situ conversion process embodiments, electrical powerused in heating an oil shale formation may be supplied from alternateenergy sources. Alternate energy sources include, but are not limitedto, solar power, wind power, hydroelectric power, geothermal power,biomass sources (i.e., agricultural and forestry by-products and energycrops), and tidal power. Electric heaters used to heat a formation mayuse any available current, voltage (AC or DC), or frequency that willnot result in damage to the heater element. Because the heaters can beoperated at a wide variety of voltages or frequencies, transformers orother conversion equipment may not be needed to allow for the use ofelectricity from alternate energy sources to power the electric heaters.This may significantly reduce equipment costs associated with usingalternate energy sources, such as wind power in which a significant costis associated with equipment that establishes a relatively narrowcurrent and/or voltage range.

[1141] Power generated from alternate energy sources may be generated ator proximate an area for treating an oil shale formation. For example,one or more solar panels and equipment for converting solar energy toelectricity may be placed at a location proximate a formation. A windfarm, which includes a plurality of wind turbines, may be placed near aformation that is to be, or is being, subjected to an in situ conversionprocess. A power station that combusts or otherwise uses local orimported biomass for electrical generation may be placed near aformation that is to be, or is being, subjected to an in situ conversionprocess. If suitable geothermal or hydroelectric sites are locatedsufficiently nearby, these resources may be used for power generation.Power for electric heaters may be generated at or proximate the locationof a formation, thus reducing costs associated with obtaining and/ortransporting electrical power. In certain embodiments, steam and/orother exhaust fluids from treating a formation may be used to power agenerator that is also primarily powered by wind turbines.

[1142] In an embodiment in which an alternate energy source such as windor solar power is used to power electric heaters, supplemental power maybe needed to complement the alternate energy source when the alternateenergy source does not provide sufficient power to supply the heaters.For example, with a wind power source, during times when there isinsufficient wind to power a wind turbine to provide power to anelectric heater, the additional power required may be obtained from linepower sources such as a fossil fuel plant or nuclear power plant. Inother embodiments, power from alternate energy sources may be used forsupplemental power in addition to power from line power sources toreduce costs associated with heating a formation.

[1143] Alternate energy sources such as wind or solar power may be usedto supplement or replace electrical grid power during peak energy costtimes. If excess electricity that is compatible with the electricitygrid is generated using alternate energy sources, the excess electricitymay be sold to the grid. If excess electricity is generated, and if theexcess energy is not easily compatible with an existing electricitygrid, the excess electricity may be used to create stored energy thatcan be recaptured at a later time. Methods of energy storage mayinclude, but are not limited to, converting water to oxygen andhydrogen, powering a flywheel for later recovery of the mechanicalenergy, pumping water into a higher reservoir for later use as ahydroelectric power source, and/or compression of air (as in undergroundcaverns or spent areas of the reservoir).

[1144] Use of wind, solar, hydroelectric, biomass, or other such energysources in an in situ conversion process essentially converts thealternate energy into liquid transportation fuels and other energycontaining hydrocarbons with a very high efficiency. Alternate energysource usage may allow reduced life cycle greenhouse gas emissions, asin many cases the alternate energy sources (other than biomass) wouldreplace an equivalent amount of power generated by fossil fuel. Even inthe case of biomass, the carbon dioxide emitted would not come fromfossil fuel, but would instead be recycled from the existing globalcarbon portfolio through photosynthesis. Unlike with fossil fuelcombustion, there would therefore be no net addition of carbon dioxideto the atmosphere. If carbon dioxide from the biomass was captured andsequestered underground or elsewhere, there may be a net removal ofcarbon from the environment.

[1145] Use of alternate energy sources may allow for formation heatingin areas where a power grid is lacking or where there otherwise isinsufficient coal, oil, or natural gas available for power generation.In embodiments of in situ conversion processes that use combustion(e.g., natural distributed combustors) for heating a portion of aformation, the use of alternate energy sources may allow start upwithout the need for construction of expensive power plants or gridconnections.

[1146] The use of alternate energy sources is not limited to supplyingelectricity for electric heaters. Alternate energy sources may also beused to supply power to surface facilities for processing fluidsproduced from a formation. Alternate energy sources may supply fuel forsurface burners or other gas combustors. For example, biomass mayproduce methane and/or other combustible hydrocarbons for reservoirheating.

[1147]FIG. 113 illustrates a schematic of an embodiment using wind togenerate electricity to heat a formation. Wind farm 6214 may include oneor more windmills. The windmills may be of any type of mechanism thatconverts wind to a usable mechanical form of motion. For example,windmill 6216 can be a design as shown in the embodiment of FIG. 113 orhave a design shown as an example in FIG. 114. In some embodiments, thewind farm may include advanced windmills as suggested by the NationalRenewable Energy Laboratory (Golden, Colo.). Wind farm 6214 may providepower to generator 6212. Generator 6212 may convert power from wind farm6214 into electrical power. In some embodiments, each windmill mayinclude a generator. Electrical power from generator 6212 may besupplied to formation 6210. The electrical power may be used information 6210 to power heaters, pumps, or any electrical equipment thatmay be used in treating formation 6210.

[1148]FIG. 115 illustrates a schematic of an embodiment for using solarpower to heat a formation. A heating fluid may be provided from storagetank 6220 to solar array 6224. The heating fluid may include any fluidthat has a relatively low viscosity with relatively good heat transferproperties (e.g., water, superheated steam, or molten ionic salts suchas molten carbonate). In certain embodiments, a low melting point ionicsalt may be used. Pump 6222 may be used to draw heating fluid fromstorage tank 6220 and provide the heating fluid to solar array 6224.Solar array 6224 may include any array designed to heat the heatingfluid to a relatively high temperature (e.g., above about 650° C.) usingsolar energy. For example, solar array 6224 may include a reflectivetrough with the heating fluid flowing through tubes within thereflective trough. The heating fluid may be provided to heater wells6230 through hot fluid conduit 6226. Each heater well 6230 may becoupled to a branch of hot fluid conduit 6226. A portion of the heatingfluid may be provided into each heater well 6230.

[1149] Each heater well 6230 may include two concentric conduits.Heating fluid may be provided into a heater well through an innerconduit. Heating fluid may then be removed from the heater well throughan outer conduit. Heat may be transferred from the heating fluid to atleast a portion of the formation within each heater well 6230 to provideheat to the formation. A portion of each heater well 6230 in anoverburden of the formation may be insulated such that no heat istransferred from the heating fluid to the overburden. Heating fluid fromeach heater well 6230 may flow into cold fluid conduit 6228, which mayreturn the heating fluid to storage tank 6220. Heating fluid may havecooled within the heater well to a temperature of about 480° C. Heatingfluid may be recirculated in a closed loop process as needed. Anadvantage of using the heating fluid to provide heat to the formationmay be that solar power is used directly to heat the formation withoutconverting the solar power to electricity.

[1150] Certain in situ conversion embodiments may include providing heatto a first portion of an oil shale formation from one or more heatsources. Formation fluids may be produced from the first portion. Asecond portion of the formation may remain unpyrolyzed by maintainingtemperature in the second portion below a pyrolysis temperature ofhydrocarbons in the formation. In some embodiments, the second portionor significant sections of the second portion may remain unheated.

[1151] A second portion that remains unpyrolyzed may be adjacent to afirst portion of the formation that is subjected to pyrolysis. Thesecond portion may provide structural strength to the formation. Thesecond portion may be between the first portion and the third portion.Formation fluids may be-produced from the third portion of theformation. A processed formation may have a pattern that resembles astriped or checkerboard pattern with alternating pyrolyzed portions andunpyrolyzed portions. In some in situ conversion embodiments, columns ofunpyrolyzed portions of formation may remain in a formation that hasundergone in situ conversion.

[1152] Unpyrolyzed portions of formation among pyrolyzed portions offormation may provide structural strength to the formation. Thestructural strength may inhibit subsidence of the formation. Inhibitingsubsidence may reduce or eliminate subsidence problems such as changingsurface levels and/or decreasing permeability and flow of fluids in theformation due to compaction of the formation.

[1153] Temperature (and average temperatures) within a heated oil shaleformation may vary depending on a number of factors. The factors mayinclude, but are not limited to proximity to a heat source, thermalconductivity and thermal diffusivity of the formation, type of reactionoccurring, type of oil shale formation, and the presence of water withinthe oil shale formation. A temperature within the oil shale formationmay be assessed using a numerical simulation model. The numericalsimulation model may calculate a subsurface temperature distribution. Inaddition, the numerical simulation model may assess various propertiesof a subsurface formation using the calculated temperature distribution.

[1154] Assessed properties of the subsurface formation may include, butare not limited to, thermal conductivity of the subsurface portion ofthe formation and permeability of the subsurface portion of theformation. The numerical simulation model may also assess variousproperties of fluid formed within a subsurface formation using thecalculated temperature distribution. Assessed properties of formed fluidmay include, but are not limited to, a cumulative volume of a fluidformed in the formation, fluid viscosity, fluid density, and acomposition of the fluid in the formation. The numerical simulationmodel may be used to assess the performance of commercial-scaleoperation of a small-scale field experiment. For example, a performanceof a commercial-scale development may be assessed based on, but is notlimited to, a total volume of product producible from a commercial-scaleoperation, amount of producible undesired products, and/or a time frameneeded before production becomes economical.

[1155] In some in situ conversion process embodiments, the in situconversion process increases a temperature or average temperature withina selected portion of an oil shale formation. A temperature or averagetemperature increase (ΔT) in a specified volume (V) of the oil shaleformation may be assessed for a given heat input rate (q) over time (t)by EQN. 33: $\begin{matrix}{{\Delta \quad T} = \frac{\sum( {q*t} )}{C_{V}*\rho_{B}*V}} & (33)\end{matrix}$

[1156] In EQN. 33, an average heat capacity of the formation (C_(v)) andan average bulk density of the formation (ρ_(B)) may be estimated ordetermined using one or more samples taken from the oil shale formation.

[1157] An in situ conversion process may include heating a specifiedvolume of oil shale formation to a pyrolysis temperature or averagepyrolysis temperature. Heat input rate (q) during a time (t) required toheat the specified volume (V) to a desired temperature increase (ΔT) maybe determined or assessed using EQN. 34:

Σq*t=ΔT*C _(V)*ρ_(B) *V  (34)

[1158] In EQN. 34, an average heat capacity of the formation (C_(v)) andan average bulk density of the formation (ρ_(B)) may be estimated ordetermined using one or more samples taken from the oil shale formation.

[1159] EQNS. 33 and 34 may be used to assess or estimate temperatures,average temperatures (e.g., over selected sections of the formation),heat input, etc. Such equations do not take into account other factors(such as heat losses), which would also have some effect on heating andtemperature assessments. However such factors can ordinarily beaddressed with correction factors.

[1160] In some in situ conversion process embodiments, a portion of anoil shale formation may be heated at a heating rate in a range fromabout 0.1° C./day to about 50° C./day. Alternatively, a portion of anoil shale formation may be heated at a heating rate in a range of about0.1° C./day to about 10° C./day. For example, a majority of hydrocarbonsmay be produced from a formation at a heating rate within a range ofabout 0.1° C./day to about 10° C./day. In addition, an oil shaleformation may be heated at a rate of less than about 0.7° C./day througha significant portion of a pyrolysis temperature range. The pyrolysistemperature range may include a range of temperatures as described inabove embodiments. For example, the heated portion may be heated at sucha rate for a time greater than 50% of the time needed to span thetemperature range, more than 75% of the time needed to span thetemperature range, or more than 90% of the time needed to span thetemperature range.

[1161] A rate at which an oil shale formation is heated may affect thequantity and quality of the formation fluids produced from the oil shaleformation. For example, heating at high heating rates (e.g., as is doneduring a Fischer Assay analysis) may allow for production of a largequantity of condensable hydrocarbons from an oil shale formation. Theproducts of such a process may be of a significantly lower quality thanwould be produced using heating rates less than about 10° C./day.Heating at a rate of temperature increase less than approximately 10°C./day may allow pyrolysis to occur within a pyrolysis temperature rangein which production of undesirable products and heavy hydrocarbons maybe reduced. In addition, a rate of temperature increase of less thanabout 3° C./day may further increase the quality of the producedcondensable hydrocarbons by further reducing the production ofundesirable products and further reducing production of heavyhydrocarbons from an oil shale formation.

[1162] In some in situ conversion process embodiments, controllingtemperature within an oil shale formation may involve controlling aheating rate within the formation. For example, controlling the heatingrate such that the heating rate is less than approximately 3° C./day mayprovide better control of temperature within the oil shale formation.

[1163] An in situ process for hydrocarbons may include monitoring a rateof temperature increase at a production well. A temperature within aportion of an oil shale formation, however, may be measured at variouslocations within the portion of the formation. An in situ process mayinclude monitoring a temperature of the portion at a midpoint betweentwo adjacent heat sources. The temperature may be monitored over time toallow for calculation of rate of temperature increase. A rate oftemperature increase may affect a composition of formation fluidsproduced from the formation. Energy input into a formation may beadjusted to change a heating rate of the formation based on calculatedrate of temperature increase in the formation to promote production ofdesired products.

[1164] In some embodiments, a power (Pwr) required to generate a heatingrate (h) in a selected volume (V) of an oil shale formation may bedetermined by EQN. 35:

Pwr=h*V*C _(V)*ρ_(B)  (35)

[1165] In EQN. 35, an average heat capacity of the oil shale formationis described as C_(V). The average heat capacity of the oil shaleformation may be a relatively constant value. Average heat capacity maybe estimated or determined using one or more samples taken from an oilshale formation, or the average heat capacity may be measured in situusing a thermal pulse test. Methods of determining average heat capacitybased on a thermal pulse test are described by I. Berchenko, E.Detournay, N. Chandler, J. Martino, and E. Kozak, “In-situ measurementof some thermoporoelastic parameters of a granite” in Poromechanics, ATribute to Maurice A. Biot., pages 545-550, Rotterdam, 1998 (Balkema),which is incorporated by reference as if fully set forth herein.

[1166] An average bulk density of the oil shale formation is describedas ρ_(B). The average bulk density of the oil shale formation may be arelatively constant value. Average bulk density may be estimated ordetermined using one or more samples taken from an oil shale formation.In certain embodiments, the product of average heat capacity and averagebulk density of the oil shale formation may be a relatively constantvalue (such product can be assessed in situ using a thermal pulse test).

[1167] A determined power may be used to determine heat provided from aheat source into the selected volume such that the selected volume maybe heated at a heating rate, h. For example, a heating rate may be lessthan about 3° C./day, and even less than about 2° C./day. A heating ratewithin a range of heating rates may be maintained within the selectedvolume. It is to be understood that in this context “power” is used todescribe energy input per time. The form of such energy input may vary(e.g., energy may be provided from electrical resistance heaters,combustion heaters, etc.).

[1168] The heating rate may be selected based on a number of factorsincluding, but not limited to, the maximum temperature possible at thewell, a predetermined quality of formation fluids that may be producedfrom the formation, and/or spacing between heat sources. A quality ofhydrocarbon fluids may be defined by an API gravity of condensablehydrocarbons, by olefin content, by the nitrogen, sulfur and/or oxygencontent, etc. In an in situ conversion process embodiment, heat may beprovided to at least a portion of an oil shale formation to produceformation fluids having an API gravity of greater than about 20°. TheAPI gravity may vary, however, depending on a number of factorsincluding the heating rate and a pressure within the portion of theformation and the time relative to initiation of the heat sources whenthe formation fluid is produced.

[1169] Subsurface pressure in an oil shale formation may correspond tothe fluid pressure generated within the formation. Heating hydrocarbonswithin an oil shale formation may generate fluids by pyrolysis. Thegenerated fluids may be vaporized within the formation. Vaporization andpyrolysis reactions may increase the pressure within the formation.Fluids that contribute to the increase in pressure may include, but arenot limited to, fluids produced during pyrolysis and water vaporizedduring heating. As temperatures within a selected section of a heatedportion of the formation increase, a pressure within the selectedsection may increase as a result of increased fluid generation andvaporization of water. Controlling a rate of fluid removal from theformation may allow for control of pressure in the formation.

[1170] In some embodiments, pressure within a selected section of aheated portion of an oil shale formation may vary depending on factorssuch as depth, distance from a heat source, a richness of thehydrocarbons within the oil shale formation, and/or a distance from aproducer well. Pressure within a formation may be determined at a numberof different locations (e.g., near or at production wells, near or atheat sources, or at monitor wells).

[1171] Heating of an oil shale formation to a pyrolysis temperaturerange may occur before substantial permeability has been generatedwithin the oil shale formation. An initial lack of permeability mayinhibit the transport of generated fluids from a pyrolysis zone withinthe formation to a production well. As heat is initially transferredfrom a heat source to an oil shale formation, a fluid pressure withinthe oil shale formation may increase proximate a heat source. Such anincrease in fluid pressure may be caused by generation of fluids duringpyrolysis of at least some hydrocarbons in the formation. The increasedfluid pressure may be released, monitored, altered, and/or controlledthrough the heat source. For example, the heat source may include avalve that allows for removal of some fluid from the formation. In someheat source embodiments, the heat source may include an open wellboreconfiguration that inhibits pressure damage to the heat source.

[1172] In some in situ conversion process embodiments, pressuregenerated by expansion of pyrolysis fluids or other fluids generated inthe formation may be allowed to increase although an open path to theproduction well or any other pressure sink may not yet exist in theformation. The fluid pressure may be allowed to increase towards alithostatic pressure. Fractures in the oil shale formation may form whenthe fluid approaches the lithostatic pressure. For example, fracturesmay form from a heat source to a production well. The generation offractures within the heated portion may relieve some of the pressurewithin the portion.

[1173] When permeability or flow channels to production wells areestablished, pressure within the formation may be controlled bycontrolling production rate from the production wells. In someembodiments, a back pressure may be maintained at production wells or atselected production wells to maintain a selected pressure within theheated portion.

[1174] A formation (e.g., an oil shale formation) may include one ormore lean zones. Lean zones may include zones with a relatively lowkerogen content (e.g., less than about 0.06 L/kg in oil shale). Richzones may include zones with a relatively high kerogen content (e.g.,greater than about 0.06 L/kg in oil shale). Lean zones may exist at anupper or lower boundary of a rich zone and/or may exist as lean zonelayers between layers of rich zone layers. Generally, lean zones may bemore permeable and include more brittle material than rich zones. Inaddition, rich zones typically have a lower thermal conductivity thanlean zones. For example, lean zones may include zones through whichfluids (e.g., water) can flow or flow through. In some cases, however,lean zones may have lower permeabilities and/or include somewhat lessbrittle material. In an in situ process for treating a formation, heatmay be applied to rich zones with substantial amounts of hydrocarbons topyrolyze and produce hydrocarbons from the rich zones. Applying heat tolean zones may be inhibited to avoid creating fractures within the leanzones (e.g., when the lean zone is at an outer boundary of theformation).

[1175] In certain embodiments, heat may be applied to a lean zone (e.g.,a lean zone between two rich zones) to create and propagate fractureswithin the lean zone. Applying heat to a lean zone and creatingfractures within the lean zone may allow for earlier production ofhydrocarbons from a formation. In some embodiments, heating of the leanzone may not be needed as fractures or high permeability is initiallypresent within the lean zone. Formation fluids may flow through apermeable lean zone more rapidly than through other portions of aformation. Formation fluids may be produced through a production wellearlier during heating of the formation in the presence of a permeablelean zone. The permeable lean zone may provide a pathway for the flow offluids between the heat front where fluids are pyrolyzed and theproduction well. Production of formation fluids through the permeablelean zone may increase the production of fluids as liquids, inhibitpressure buildup in the formation, inhibit failure/collapse of wells dueto high pressures, and/or allow for convective heat transfer through thefractures.

[1176]FIG. 116 depicts a cross-sectional representation of an embodimentfor treating lean zones 8690 and rich zones 8691 of a formation. Leanzones 8690 and rich zones 8691 are below overburden 540. In someembodiments, lean zones 8690 may be relatively permeable sections of theformation. For example, lean zones 8690 may have an average permeabilitythickness product of greater than about 100 millidarcy feet. In certainembodiments, lean zones 8690 may have an average permeability thicknessproduct of greater than about 1000 millidarcy feet or greater than about5000 millidarcy feet. Rich zones 8691 may be sections of the formationthat are selected for treatment based on a richness of the section. Richzones 8691 may have an initial average permeability thickness product ofless than about 10 millidarcy feet. Certain rich zones may have aninitial average permeability thickness product of less than about 1millidarcy feet or less than about 0.5 millidarcy feet.

[1177] Heat source 8692 may be placed through overburden 540 and intoopening 514. Reinforcing material 544 (e.g., cement) may seal a portionof opening 514 to overburden 540. Heat source 8692 may apply heat tolean zones 8690 and/or rich zones 8691. In some embodiments, heat source8692 may include a conductor with a thickness that is adjusted toprovide more heat to rich zones 8691 than lean zones 8690 (i.e., thethickness of the conductor is larger proximate the lean zones than thethickness of the conductor proximate the rich zones).

[1178] In certain embodiments, rich zones 8691 may not fracture. Forexample, the rich zones may have a ductility that is high enough toinhibit the formation of fractures. A formation (e.g., an oil shaleformation) may have one or more lean zones 8690 and one or more richzones 8691 that are layered throughout the formation as shown in FIG.116. Formation fluids formed in rich zones 8691 may be produced throughpre-existing fractures in lean zone 8690. In some embodiments, lean zone8690 may have a permeability sufficiently high to allow production offluids. This high permeability may be initially present in the lean zonebecause of, for example, water flow through the lean zone that leachedout minerals over geological time prior to initiation of the in situconversion process. In some embodiments, the application of heat to theformation from heat sources may produce, or increase the size of,fractures 8696 and/or increase the permeability in lean zones 8690.Fractures 8696 may increase the permeability of lean zones 8690 byproviding a pathway for fluids to propagate through the lean zones.

[1179] During early times of heating, permeability may be created nearopening 514. Permeability may be created in permeable zone 8695 adjacentopening 514. Permeable zone 8695 will increase in size and move outradially as the heat front produced by heat source 8692 moves outward.As the heat front migrates through the formation, hydrocarbons may bepyrolyzed as temperatures within rich zones 8691 reach pyrolysistemperatures. Pyrolyzation of the hydrocarbons, along with heating ofthe rich zones, may increase the permeability of rich zones 8691. Atlater times of heating, hydrocarbons in coking portion 8693 of permeablezone 8695 may coke as temperatures within this portion increase tocoking temperatures. At some point permeable zone 8695 will move outwardto a distance from opening 514 at which no coking of hydrocarbons occurs(i.e., a distance at which temperatures do not approach cokingtemperatures). Permeable zone 8695 may continue to expand with themigration of the heat front through the formation. If sufficient wateris present, coking may be suppressed near opening 514.

[1180] In certain embodiments, fluids formed in rich zones 8691 may flowinto lean zones 8690 through permeable zone 8695. Coking portion 8693may inhibit the flow of fluids between rich zones 8691 and lean zones8690. Fluids may continue to flow into lean zones 8690 through un-cokedportions of permeable zone 8695. In some embodiments, fluids may flow toopening 514 (e.g., during early times of heating before permeable zone8695 has sufficient permeability for fluid flow into the lean zones).Fluids that flow to opening 514 may be produced through the opening orbe allowed to flow through lean zones 8690 to production well 8698. Inaddition, during early times of heating, some coke formation may occurnear opening 514.

[1181] Allowing formation fluids to be produced through lean zones 8690may allow for earlier production of fluids formed in rich zones 8691.For example, fluids formed in rich zones 8690 may be produced throughlean zones 8690 before sufficient permeability has been created in therich zones for fluids to flow directly within the rich zones toproduction well 8698. Producing at least some fluids through lean zone8690 or through opening 514 may inhibit a buildup of pressure within theformation during heating of the formation.

[1182] In certain embodiments, fractures 8696 may propagate in ahorizontal direction. However, fractures 8696 may propagate in otherdirections depending on, for example, a depth of the fracturing layerand structure of the fracturing layer. As an example, oil shaleformations in the Piceance basin in Colorado that are deeper than about125 m below the surface tend to have fractures that propagate at anangle or vertically. In certain embodiments, the creation of angled orvertical fractures may be inhibited to inhibit fracturing into anaquifer or other environmentally sensitive area.

[1183] In some embodiments, applying heat to rich zones 8691 may createfractures within the rich zones. Fractures within rich zone 8691 may beless likely to initially occur due to the more ductile (less brittle)composition of the rich zone as compared to lean zones 8690. In anembodiment, fractures may develop that connect lean zones 8690 and richzones 8691. These fractures may provide a path for propagation of fluidsfrom one zone to the other zone.

[1184] Production well 8698 may be placed at an angle, vertically, orhorizontally into lean zones 8690 and rich zones 8691. Production well8698 may produce formation fluids from lean zones 8690 and/or rich zones8691.

[1185] In some embodiments, more than one production well may be placedin lean zones 8690 and/or rich zones 8691. A number of production wellsmay be determined by, for example, a desired product quality of theproduced fluids, a desired production rate, a desired weight percentageof a component in the produced fluids, etc.

[1186] In other embodiments, formation fluids may be produced throughopening 514, which may be uncased or perforated. Producing formationfluids through opening 514 tends to increase cracking of hydrocarbons(from the heat provided by heat source 8692) as the fluids propagatealong the length of the opening. Fluids produced through opening 514 mayhave lower carbon numbers than fluids produced through production well8698.

[1187] In an in situ conversion process embodiment, pressure may beincreased within a selected section of a portion of an oil shaleformation to a selected pressure during pyrolysis. A selected pressuremay be within a range from about 2 bars absolute to about 72 barsabsolute or, in some embodiments, 2 bars absolute to 36 bars absolute.Alternatively, a selected pressure may be within a range from about 2bars absolute to about 18 bars absolute. In some in situ conversionprocess embodiments, a majority of hydrocarbon fluids may be producedfrom a formation having a pressure within a range from about 2 barsabsolute to about 18 bars absolute. The pressure during pyrolysis mayvary or be varied. The pressure may be varied to alter and/or control acomposition of a formation fluid produced, to control a percentage ofcondensable fluid as compared to non-condensable fluid, and/or tocontrol an API gravity of fluid being produced. For example, decreasingpressure may result in production of a larger condensable fluidcomponent. The condensable fluid component may contain a largerpercentage of olefins.

[1188] In some in situ conversion process embodiments, increasedpressure due to fluid generation may be maintained within the heatedportion of the formation. Maintaining increased pressure within aformation may inhibit formation subsidence during in situ conversion.Increased formation pressure may promote generation of high qualityproducts during pyrolysis. Increased formation pressure may facilitatevapor phase production of fluids from the formation. Vapor phaseproduction may allow for a reduction in size of collection conduits usedto transport fluids produced from the formation. Increased formationpressure may reduce or eliminate the need to compress formation fluidsat the surface to transport the fluids in collection conduits to surfacefacilities. Maintaining increased pressure within a formation may alsofacilitate generation of electricity from produced non-condensablefluid. For example, the produced non-condensable fluid may be passedthrough a turbine to generate electricity.

[1189] Increased pressure in the formation may also be maintained toproduce more and/or improved formation fluids. In certain in situconversion process embodiments, significant amounts (e.g., a majority)of the hydrocarbon fluids produced from a formation may benon-condensable hydrocarbons. Pressure may be selectively increasedand/or maintained within the formation to promote formation of smallerchain hydrocarbons in the formation. Producing small chain hydrocarbonsin the formation may allow more non-condensable hydrocarbons to beproduced from the formation. The condensable hydrocarbons produced fromthe formation at higher pressure may be of a higher quality (e.g.,higher API gravity) than condensable hydrocarbons produced from theformation at a lower pressure.

[1190] A high pressure may be maintained within a heated portion of anoil shale formation to inhibit production of formation fluids havingcarbon numbers greater than, for example, about 25. Some high carbonnumber compounds may be entrained in vapor in the formation and may beremoved from the formation with the vapor. A high pressure in theformation may inhibit entrainment of high carbon number compounds and/ormulti-ring hydrocarbon compounds in the vapor. Increasing pressurewithin the oil shale formation may increase a boiling point of a fluidwithin the portion. High carbon number compounds and/or multi-ringhydrocarbon compounds may remain in a liquid phase in the formation forsignificant time periods. The significant time periods may providesufficient time for the compounds to pyrolyze to form lower carbonnumber compounds.

[1191] Maintaining increased pressure within a heated portion of theformation may surprisingly allow for production of large quantities ofhydrocarbons of increased quality. Maintaining increased pressure maypromote vapor phase transport of pyrolyzation fluids within theformation. Increasing the pressure often permits production of lowermolecular weight hydrocarbons since such lower molecular weighthydrocarbons will more readily transport in the vapor phase in theformation.

[1192] Generation of lower molecular weight hydrocarbons (andcorresponding increased vapor phase transport) is believed to be due, inpart, to autogenous generation and reaction of hydrogen within a portionof the oil shale formation. For example, maintaining an increasedpressure may force hydrogen generated during pyrolysis into a liquidphase (e.g., by dissolving). Heating the portion to a temperature withina pyrolysis temperature range may pyrolyze hydrocarbons within theformation to generate pyrolyzation fluids in a liquid phase. Thegenerated components may include double bonds and/or radicals. H₂ in theliquid phase may reduce double bonds of the generated pyrolyzationfluids, thereby reducing a potential for polymerization or formation oflong chain compounds from the generated pyrolyzation fluids. Inaddition, hydrogen may also neutralize radicals in the generatedpyrolyzation fluids. Therefore, H₂ in the liquid phase may inhibit thegenerated pyrolyzation fluids from reacting with each other and/or withother compounds in the formation. Shorter chain hydrocarbons may enterthe vapor phase and may be produced from the formation.

[1193] Increasing the formation pressure may reduce the potential forcoking within a selected section of the formation. Coking reactions mayoccur substantially in a liquid phase at high temperatures. Cokingreactions may occur in localized sections of the formation. An in situconversion process embodiment may slowly raise temperature within aselected section. Pyrolysis reactions that occur in a liquid phase mayresult in the production of small molecules in the liquid phase. Thesmall molecules may leave the liquid as a vapor due to local temperatureand pressure conditions. The small molecules undergoing phase changefrom a liquid phase to a vapor phase may absorb a significant amount ofheat. The absorbed heat may help to inhibit high temperatures that couldresult in coking reactions. In addition, increased pressure in theformation may result in a significant amount of hydrogen being forcedinto the liquid phase present in the formation. The hydrogen may inhibitpolymerization reactions that result in the generation of largehydrocarbon molecules. Inhibiting the production of large hydrocarbonmolecules may result in less coking within the formation.

[1194] Operating an in situ conversion process at increased pressure mayallow for vapor phase production of formation fluid from the formation.Vapor phase production may permit increased recovery of lighter (andrelatively high quality) pyrolyzation fluids. Vapor phase production mayresult in less formation fluid being left in the formation after thefluid is produced by pyrolysis. Vapor phase production may allow forfewer production wells in the formation than is present using liquidphase or liquid/vapor phase production. Fewer production wells maysignificantly reduce equipment costs associated with an in situconversion process.

[1195] In an embodiment, a portion of an oil shale formation may beheated to increase a partial pressure of H₂. In some embodiments, anincreased H₂ partial pressure may include H₂ partial pressures in arange from about 0.5 bars absolute to about 7 bars absolute.Alternatively, an increased H₂ partial pressure range may include H₂partial pressures in a range from about 5 bars absolute to about 7 barsabsolute. For example, a majority of hydrocarbon fluids may be producedwherein a H₂ partial pressure is within a range of about 5 bars absoluteto about 7 bars absolute. A range of H₂ partial pressures within thepyrolysis H₂ partial pressure range may vary depending on, for example,temperature and pressure of the heated portion of the formation.

[1196] Maintaining a H₂ partial pressure within the formation of greaterthan atmospheric pressure may increase an API value of producedcondensable hydrocarbon fluids. Maintaining an increased H₂ partialpressure may increase an API value of produced condensable hydrocarbonfluids to greater than about 25° or, in some instances, greater thanabout 30°. Maintaining an increased H₂ partial pressure within a heatedportion of an oil shale formation may increase a concentration of H₂within the heated portion. The H₂ may be available to react withpyrolyzed components of the hydrocarbons. Reaction of H₂ with thepyrolyzed components of hydrocarbons may reduce polymerization ofolefins into tars and other cross-linked, difficult to upgrade,products. Therefore, production of hydrocarbon fluids having low APIgravity values may be inhibited.

[1197] In an embodiment, a method for treating an oil shale formation insitu may include adding hydrogen to a selected section of the formationwhen the selected section is at or undergoing certain conditions. Forexample, the hydrogen may be added through a heater well or productionwell located in or proximate the selected section. Since hydrogen issometimes in relatively short supply (or relatively expensive to make orprocure), hydrogen may be added when conditions in the formationoptimize the use of the added hydrogen. For example, hydrogen producedin a section of a formation undergoing synthesis gas generation may beadded to a section of the formation undergoing pyrolysis. The addedhydrogen in the pyrolysis section of the formation may promote formationof aliphatic compounds and inhibit formation of olefinic compounds thatreduce the quality of hydrocarbon fluids produced from formation.

[1198] In some embodiments, hydrogen may be added to the selectedsection after an average temperature of the formation is at a pyrolysistemperature (e.g., when the selected section is at least about 270° C.).In some embodiments, hydrogen may be added to the selected section afterthe average temperature is at least about 290° C., 320° C., 375° C., or400° C. Hydrogen may be added to the selected section before an averagetemperature of the formation is about 400° C. In some embodiments,hydrogen may be added to the selected section before the averagetemperature is about 300° C. or about 325° C.

[1199] The average temperature of the formation may be controlled byselectively adding hydrogen to the selected section of the formation.Hydrogen added to the formation may react in exothermic reactions. Theexothermic reactions may heat the formation and reduce the amount ofenergy that needs to be supplied from heat sources to the formation. Insome embodiments, an amount of hydrogen may be added to the selectedsection of the formation such that an average temperature of theformation does not exceed about 400° C.

[1200] A valve may maintain, alter, and/or control a pressure within aheated portion of an oil shale formation. For example, a heat sourcedisposed within an oil shale formation may be coupled to a valve. Thevalve may release fluid from the formation through the heat source. Inaddition, a pressure valve may be coupled to a production well withinthe oil shale formation. In some embodiments, fluids released by thevalves may be collected and transported to a surface unit for furtherprocessing and/or treatment.

[1201] An in situ conversion process for hydrocarbons may includeproviding heat to a portion of an oil shale formation and controlling atemperature, rate of temperature increase, and/or pressure within theheated portion. A temperature and/or a rate of temperature increase ofthe heated portion may be controlled by altering the energy supplied toheat sources in the formation.

[1202] Controlling pressure and temperature within an oil shaleformation may allow properties of the produced formation fluids to becontrolled. For example, composition and quality of formation fluidsproduced from the formation may be altered by altering an averagepressure and/or an average temperature in a selected section of a heatedportion of the formation. The quality of the produced fluids may beevaluated based on characteristics of the fluid such as, but not limitedto, API gravity, percent olefins in the produced formation fluids,ethene to ethane ratio, atomic hydrogen to carbon ratio, percent ofhydrocarbons within produced formation fluids having carbon numbersgreater than 25, total equivalent production (gas and liquid), totalliquids production, and/or liquid yield as a percent of Fischer Assay.Controlling the quality of the produced formation fluids may includecontrolling average pressure and average temperature in the selectedsection such that the average assessed pressure in the selected sectionis greater than the pressure (p) as set forth in the form of EQN. 36 foran assessed average temperature (T) in the selected section:$\begin{matrix}{p = \exp^{\lbrack{\frac{A}{T} + B}\rbrack}} & (36)\end{matrix}$

[1203] where p is measured in psia (pounds per square inch absolute), Tis measured in Kelvin, and A and B are parameters dependent on the valueof the selected property.

[1204] EQN. 36 may be rewritten such that the natural log of pressure isa linear function of the inverse of temperature. This form of EQN. 36 isexpressed as: ln(p)=A/T+B. In a plot of the absolute pressure as afunction of the reciprocal of the absolute temperature, A is the slopeand B is the intercept. The intercept B is defined to be the naturallogarithm of the pressure as the reciprocal of the temperatureapproaches zero. The slope and intercept values (A and B) of thepressure-temperature relationship may be determined from at least twopressure-temperature data points for a given value of a selectedproperty. The pressure-temperature data points may include an averagepressure within a formation and an average temperature within theformation at which the particular value of the property was, or may be,produced from the formation. The pressure-temperature data points may beobtained from an experiment such as a laboratory experiment or a fieldexperiment.

[1205] A relationship between the slope parameter, A, and a value of aproperty of formation fluids may be determined. For example, values of Amay be plotted as a function of values of a formation fluid property. Acubic polynomial may be fitted to these data. For example, a cubicpolynomial relationship such as EQN. 37:

A=a ₁*(property)³ +a ₂*(property)² +a ₃*(property)+a ₄;  (37)

[1206] may be fitted to the data, where a₁, a₂, a₃, and a₄ are empiricalconstants that describe a relationship between the first parameter, A,and a property of a formation fluid. Alternatively, relationships havingother functional forms such as another order polynomial, trigonometricfunction, or a logarithmic function may be fitted to the data. Valuesfor a₁, a₂, . . . , may be estimated from the results of the datafitting. Similarly, a relationship between the second parameter, B, anda value of a property of formation fluids may be determined. Forexample, values of B may be plotted as a function of values of aproperty of a formation fluid. A cubic polynomial may also be fitted tothe data. For example, a cubic polynomial relationship such as EQN. 38:

B=b ₁*(property)³ +b ₂*(property)² +b ₃*(property)+b ₄;  (38)

[1207] may be fitted to the data, where b₁, b₂, b₃, and b₄ are empiricalconstants that may describe a relationship between the parameter B andthe value of a property of a formation fluid. As such, b₁, b₂, b₃, andb₄ may be estimated from results of fitting the data. TABLES 6and 7 listestimated empirical constants determined for several properties of aformation fluid produced by an in situ conversion process from GreenRiver oil shale. TABLE 6 PROPERTY a₁ a₂ a₃ a₄ API Gravity −0.738549−8.893902 4752.182 −145484.6 Ethene/Ethane Ratio −15543409 3261335−303588.8 −2767.469 Weight Percent of 0.1621956 −8.85952 547.9571−24684.9 Hydrocarbons Having a Carbon Number Greater Than 25 Atomic H/CRatio 2950062 −16982456 32584767 −20846821 Liquid Production (gal/ton)119.2978 −5972.91 96989 −524689 Equivalent Liquid Production −6.24976212.9383 −777.217 −39353.47 (gal/ton) % Fischer Assay 0.5026013 −126.5929813.139 −252736

[1208] TABLE 7 PROPERTY b₁ b₂ b₃ b₄ API Gravity 0.003843 −0.2794243.391071 96.67251 Ethene/Ethane Ratio −8974.317 2593.058 −40.7887423.31395 Weight Percent of Hydrocarbons −0.0005022 0.026258 −1.1269544.49521 Having a Carbon Number Greater Than 25 Atomic H/C Ratio790.0532 −4199.454 7328.572 −4156.599 Liquid Production (gal/ton)−0.17808 8.914098 −144.999 793.2477 Equivalent Liquid Production−0.03387 2.778804 −72.6457 650.7211 (gal/ton) % Fischer Assay −0.00079010.196296 −15.1369 395.3574

[1209] To determine an average pressure and an average temperature forproducing a formation fluid having a selected property, the value of theselected property and the empirical constants may be used to determinevalues for the first parameter A and the second parameter B, accordingto EQNS. 39 and 40:

A=a ₁*(property)³ +a ₂*(property)² +a ₃*(property)+a ₄  (39)

B=b ₁*(property)³ +b ₂*(property)² +b ₃*(property)+b ₄  (40)

[1210] TABLES 8-14 list estimated values for the parameter A andapproximate values for the parameter B, as determined for a selectedproperty of a formation fluid produced by an in situ conversion processfrom Green River oil shale. TABLE 8 API Gravity A B 20° −59906.983.46594 25° 43778.5 66.85148 30° −30864.5 50.67593 35° −21718.537.82131 40° −16894.7 31.16965 45° −16946.8 33.60297

[1211] TABLE 9 Ethene/Ethane Ratio A B 0.20 −57379 83.145 0.10 −1605627.652 0.05 −11736 21.986 0.01 −5492.8 14.234

[1212] TABLE 10 Weight Percent of Hydrocarbons Having a Carbon NumberGreater Than 25 A B 25% −14206 25.123 20% −15972 28.442 15% −1791231.804 10% −19929 35.349  5% −21956 38.849  1% −24146 43.394

[1213] TABLE 11 Atomic H/C Ratio A B 1.7 −38360 60.531 1.8 −12635 23.9891.9 −7953.1 17.889 2.0 −6613.1 16.364

[1214] TABLE 12 Liquid Production (gal/ton) A B 14 gal/ton −10179 21.78016 gal/ton −13285 25.866 18 gal/ton −18364 32.882 20 gal/ton −1968934.282

[1215] TABLE 13 Equivalent Liquid Production (gal/ton) A B 20 gal/ton−19721 38.338 25 gal/ton −23350 42.052 30 gal/ton −39768.9 57.68

[1216] TABLE 14 % Fischer Assay A B 60% −11118 23.156 70% −13726 26.63580% −20543 36.191 90% −28554 47.084

[1217] In some in situ conversion process embodiments, the determinedvalues for the parameter A and the parameter B may be used to determinean average pressure in the selected section of the formation using anassessed average temperature, T, in the selected section. For example,an average pressure of the selected section may be determined by EQN.41:

p=exp[(A/T)+B],  (41)

[1218] in which p is expressed in psia, and T is expressed in Kelvin.Alternatively, an average absolute pressure of the selected section,measured in bars, may be determined using EQN. 42:

P _(bars)=exp[(A/T)+B−2.6744].  (42)

[1219] An average pressure within the selected section may be controlledsuch that the average pressure within the selected section is about thevalue calculated from the equation. Formation fluid produced from theselected section may approximately have the chosen value of the selectedproperty, and therefore, the desired quality.

[1220] In some in situ conversion process embodiments, the determinedvalues for the parameter A and the parameter B may be used to determinean average temperature in the selected section of the formation using anassessed average pressure, p, in the selected section. Using therelationships described above, an average temperature within theselected section may be controlled to approximate the calculated averagetemperature to produce hydrocarbon fluids having a selected property andquality.

[1221] Formation fluid properties may vary depending on a location of aproduction well in the formation. For example, a location of aproduction well with respect to a location of a heat source in theformation may affect the composition of formation fluid produced fromthe formation. Distance between a production well and a heat source inthe formation may be varied to alter the composition of formation fluidproducible from the formation. Having a short distance between aproduction well and a heat source or heat sources may allow a hightemperature to be maintained at and adjacent to the production well.Having a high temperature at and adjacent to the production well mayallow a substantial portion of pyrolyzation fluids flowing to andthrough the production well to crack to non-condensable compounds. Insome in situ conversion process embodiments, location of productionwells relative to heat sources may be selected to allow for productionof formation fluid having a large non-condensable gas fraction. In somein situ conversion process embodiments, location of production wellsrelative to heat sources may be selected to increase a condensable gasfraction of the produced formation fluids. During operation of in situconversion process embodiments, energy input into heat sources adjacentto production wells may be controlled to allow for production of adesired ratio of non-condensable to condensable hydrocarbons.

[1222] A carbon number distribution of a produced formation fluid mayindicate a quality of the produced formation fluid. In general,condensable hydrocarbons with low carbon numbers are considered to bemore valuable than condensable hydrocarbons having higher carbonnumbers. Low carbon numbers may include, for example, carbon numbersless than about 25. High carbon numbers may include carbon numbersgreater than about 25. In an in situ conversion process embodiment, thein situ conversion process may include providing heat to a portion of aformation so that a majority of hydrocarbons produced from the formationhave carbon numbers of less than approximately 25.

[1223] An in situ conversion process may be operated so that carbonnumbers of the largest weight fraction of hydrocarbons produced from theformation are about 12, for a given time period. The time period may betotal time of operation, or a selected subset of operation (e.g., a day,week, month, year, etc.). Operating conditions of an in situ conversionprocess may be adjusted to shift the carbon number of the largest weightfraction of hydrocarbons produced from the formation. For example,increasing pressure in a formation may shift the carbon number of thelargest weight fraction of hydrocarbons produced from the formation to asmaller carbon number. Shifting the carbon number of the largest weightfraction of hydrocarbons produced from the formation may also beexpressed as shifting the mean carbon number of the carbon numberdistribution.

[1224] In some in situ conversion process embodiments, hydrocarbonsproduced from the formation may have a mean carbon number less thanabout 25. In some in situ conversion process embodiments, less thanabout 15 weight % of the hydrocarbons in the condensable hydrocarbonshave carbon numbers greater than approximately 25. In some embodiments,less than about 5 weight % of hydrocarbons in the condensablehydrocarbons have carbon numbers greater than about 25, and/or less thanabout 2 weight % of hydrocarbons in the condensable hydrocarbons havecarbon numbers greater than about 25.

[1225] In an in situ conversion process embodiment, the in situconversion process may include providing heat to at least a portion ofan oil shale formation at a rate sufficient to alter and/or controlproduction of olefins. The in situ conversion process may includeheating the portion at a rate to produce formation fluids having anolefin content of less than about 10 weight % of condensablehydrocarbons of the formation fluids. Reducing olefin production mayreduce coating of pipe surfaces by the olefins, thereby reducingdifficulty associated with transporting hydrocarbons through the piping.Reducing olefin production may inhibit polymerization of hydrocarbonsduring pyrolysis, thereby increasing permeability in the formationand/or enhancing the quality of produced fluids (e.g., by lowering themean carbon number of the carbon number distribution for fluids producedfrom the formation, increasing API gravity, etc.).

[1226] In some in situ conversion process embodiments, however, theportion may be heated at a rate to allow for production of olefins fromformation fluid in sufficient quantities to allow for economic recoveryof the olefins. Olefins in produced formation fluid may be separatedfrom other hydrocarbons. Operating conditions (i.e., temperature andpressure) within the formation may be selected to control thecomposition of olefins produced along with other formation fluid. Forexample, operating conditions of an in situ conversion process may beselected to produce a carbon number distribution with a mean carbonnumber of about 9. Only a small weight fraction of the olefins producedmay have carbon numbers greater than 9. The small weight fraction maynot significantly affect the quality (e.g., API gravity) of the producedfluid from the formation. The fluid may remain easy to process even withenough olefins present to make separation of olefins economicallyviable.

[1227] In some in situ conversion process embodiments, a portion of theformation may be heated at a rate to selectively increase the content ofphenol and substituted phenols of condensable hydrocarbons in theproduced fluids. For example, phenol and/or substituted phenols may beseparated from condensable hydrocarbons. The separated compounds may beused to produce additional products. The resource may, in someembodiments, be selected to enhance production of phenol and/orsubstituted phenols.

[1228] Hydrocarbons in produced fluids may include a mixture of a numberof different hydrocarbon components. Hydrocarbons in formation fluidproduced from a formation may have a hydrogen to carbon atomic ratiothat is at least approximately 1.7 or above. For example, the hydrogento carbon atomic ratio of a produced fluid may be approximately 1.8,approximately 1.9, or greater. The ratio may be below two because of thepresence of aromatic compounds and/or olefins. Some of the hydrocarboncomponents are condensable and some are not. The fraction ofnon-condensable hydrocarbons within the produced fluid may be alteredand/or controlled by altering, controlling, and/or maintaining a hightemperature and/or high pressure during pyrolysis within the formation.Surface facilities may separate hydrocarbon fluids from non-hydrocarbonfluids. Surface facilities may also separate condensable hydrocarbonsfrom non-condensable hydrocarbons.

[1229] In some embodiments, the non-condensable hydrocarbons may includehydrocarbons having carbon numbers less than or equal to 5. Producedformation fluid may also include non-hydrocarbon, non-condensable fluidssuch as, but not limited to, H₂, CO₂, ammonia, H₂S, N₂ and/or CO. Incertain embodiments, non-condensable hydrocarbons of a fluid producedfrom a portion of an oil shale formation may have a weight ratio ofhydrocarbons having carbon numbers from 2 through 4 (“C₂₋₄hydrocarbons”) to methane of greater than about 0.3, greater than about0.75, or greater than about 1 in some circumstances. Hydrocarbonresource characteristics may influence the ratio of C₂₋₄ hydrocarbons tomethane. For example, a ratio of C₂₋₄ hydrocarbons to methane for an oilshale formation may be about 1. Operating conditions (e.g., temperatureand pressure) may be adjusted to influence a ratio of C₂₋₄ hydrocarbonsto methane. For example, producing hydrocarbons from a relatively hotformation at a relatively high formation may produce significant amountof methane, which may result in a significantly lower value for theratio of C₂₋₄ hydrocarbons to methane as compared to fluid produced fromthe same formation at milder temperature and pressure conditions.

[1230] An in situ conversion process may be able to produce a highweight ratio of C₂₋₄ hydrocarbons to methane as compared to ratiosproducible using other processes such as fire floods or steam floods.High weight ratios of C₂₋₄ hydrocarbons to methane may indicate thepresence of significant amounts of hydrocarbons with 2, 3, and/or 4carbons (e.g., ethane, ethene, propane, propene, butane, and butene).C₂₋₄ hydrocarbons may have significant value. The value of C₃ and C₄hydrocarbons may be many times (e.g., 2, 3, or greater) than the valueof methane. Production of hydrocarbon fluids having high C₂₋₄hydrocarbons to methane weight ratios may be due to conditions appliedto the formation during pyrolysis (e.g., controlled heating and/orpressure used in reducing environments or non-oxidizing environments).The conditions may allow for long chain hydrocarbons to be reduced tosmall (and in many cases more saturated) chain hydrocarbons with only aportion of the long chain hydrocarbons being reduced to methane orcarbon dioxide.

[1231] Methane and at least a portion of ethane may be separated fromnon-condensable hydrocarbons in produced fluid. The methane and ethanemay be utilized as natural gas. A portion of propane and butane may beseparated from non-condensable hydrocarbons of the produced fluid. Inaddition, the separated propane and butane may be utilized as fuels oras feedstocks for producing other hydrocarbons. Ethane, propane andbutane produced from the formation may be used to generate olefins. Aportion of the produced fluid having carbon numbers less than 4 may bereformed to produce additional H₂ and/or methane. In some in situconversion process embodiments, the reformation may be performed in theformation. In addition, ethane, propane, and butane may be separatedfrom the non-condensable hydrocarbons.

[1232] Formation fluid produced from a formation during a pyrolysisstage of an in situ conversion process may have a H₂ content of greaterthan about 5 weight %, greater than about 10 weight %, or even greaterthan about 15 weight %. The H₂ may be used for a variety of purposes.The purposes may include, but are not limited to, as a fuel for a fuelcell, to hydrogenate hydrocarbon fluids in situ, and/or to hydrogenatehydrocarbon fluids ex situ.

[1233] Formation fluid produced from a formation may include somehydrogen sulfide. The hydrogen sulfide may be a non-condensable,non-hydrocarbon component of the formation fluid. The hydrogen sulfidemay be separated from other compounds. The separated hydrogen sulfidemay be used to produce, for example, sulfuric acid, fertilizer, and/orelemental sulfur.

[1234] Formation fluid produced from a formation during in situconversion may include carbon dioxide. Carbon dioxide produced from theformation may be used for a variety of purposes. The purposes mayinclude, but are not limited to, drive fluid for enhanced oil recovery,drive fluid for coal bed methane production, as a feedstock forproduction of urea, and/or a component of a synthesis gas fluidgenerating fluid. In some embodiments, a portion of carbon dioxideproduced during an in situ conversion process may be sequestered in aspent portion of the formation being processed.

[1235] Formation fluid produced from a formation during in situconversion may include carbon monoxide. Carbon monoxide produced fromthe formation may be used, for example, as a feedstock for a fuel cell,as a feedstock for a Fischer-Tropsch process, as a feedstock forproduction of methanol, and/or as a feedstock for production of methane.

[1236] Condensable hydrocarbons of formation fluids produced from aformation may be separated from the formation fluids. Formation fluidsmay be separated into a non-condensable portion (hydrocarbon andnon-hydrocarbon) and a condensable portion (hydrocarbon andnon-hydrocarbon). The condensable portion may include condensablehydrocarbons and compounds found in an aqueous phase. The aqueous phasemay be separated from the condensable component.

[1237] An aqueous phase may include ammonia. The ammonia content of thetotal produced fluids may be greater than about 0.1 weight % of thefluid, greater than about 0.5 weight % of the fluid, and, in someembodiments, up to about 10 weight % of the produced fluids. The ammoniamay be used to produce, for example, urea.

[1238] In certain embodiments, a fluid produced from a formation mayinclude oxygenated hydrocarbons. For example, condensable hydrocarbonsof the produced fluid may include an amount of oxygenated hydrocarbonsgreater than about 5 weight % of the condensable hydrocarbons.Alternatively, the condensable hydrocarbons may include an amount ofoxygenated hydrocarbons greater than about 0.1 weight % of thecondensable hydrocarbons. Furthermore, the condensable hydrocarbons mayinclude an amount of oxygenated hydrocarbons greater than about 1.0weight % of the condensable hydrocarbons or greater than about 2.0weight % of the condensable hydrocarbons. The oxygenated hydrocarbonsmay include, but are not limited to, phenol and/or substituted phenols.In some embodiments, phenol and substituted phenols may have moreeconomic value than many other products produced from an in situconversion process. Therefore, an in situ conversion process may beutilized to produce phenol and/or substituted phenols. For example,generation of phenol and/or substituted phenols may increase when afluid pressure within the formation is maintained at a lower pressure.

[1239] In some in situ conversion process embodiments, condensablehydrocarbons of a fluid produced from an oil shale formation may includeolefins. For example, an olefin content of the condensable hydrocarbonsmay be in a range from about 0.1 weight % to about 15 weight %.Alternatively, an olefin content of the condensable hydrocarbons may bewithin a range from about 0.1 weight % to about 5 weight %. An olefincontent of the condensable hydrocarbons may also be within a range fromabout 0.1 weight % to about 2.5 weight %. An olefin content of thecondensable hydrocarbons may be altered and/or controlled by controllinga pressure and/or a temperature within the formation. For example,olefin content of the condensable hydrocarbons may be reduced byselectively increasing pressure within the formation, by selectivelydecreasing temperature within the formation, by selectively reducingheating rates within the formation, and/or by selectively increasinghydrogen partial pressures in the formation. In some in situ conversionprocess embodiments, a reduced olefin content of the condensablehydrocarbons may be desired. For example, if a portion of the producedfluids is used to produce motor fuels, a reduced olefin content may bedesired.

[1240] In some in situ conversion process embodiments, a higher olefincontent may be desired. For example, if a portion of the condensablehydrocarbons may be sold, a higher olefin content may be selected due toa high economic value of olefin products. In some embodiments, olefinsmay be separated from the produced fluids and then sold and/or used as afeedstock for the production of other compounds.

[1241] Non-condensable hydrocarbons of a produced fluid may includeolefins. An ethene/ethane molar ratio may be used as an estimate ofolefin content of non-condensable hydrocarbons. In certain in situconversion process embodiments, the ethene/ethane molar ratio may rangefrom about 0.001 to about 0.15.

[1242] Fluid produced from an oil shale formation may include aromaticcompounds. For example, the condensable hydrocarbons may include anamount of aromatic compounds greater than about 20 weight % or about 25weight % of the condensable hydrocarbons. Alternatively, the condensablehydrocarbons may include an amount of aromatic compounds greater thanabout 30 weight % of the condensable hydrocarbons. The condensablehydrocarbons may also include relatively low amounts of compounds withmore than two rings in them (e.g., tri-aromatics or above). For example,the condensable hydrocarbons may include less than about 1 weight % orless than about 2 weight % of tri-aromatics or above in the condensablehydrocarbons. Alternatively, the condensable hydrocarbons may includeless than about 5 weight % of tri-aromatics or above in the condensablehydrocarbons.

[1243] Fluid produced from an oil shale formation may include a smallamount of asphaltenes (i.e., large multi-ring aromatics that may besubstantially soluble in hydrocarbons) as compared to fluid producedfrom a formation using other techniques such as fire floods and/or steamfloods. Temperature and pressure control within a selected portion mayinhibit the production of asphaltenes using an in situ conversionprocess. Some asphaltenes may be entrained in formation fluid producedfrom the formation. Asphaltenes may make up less than about 0.3 weight %of the condensable hydrocarbons produced using an in situ conversionprocess. In some in situ conversion process embodiments, asphaltenes maybe less than 0.1 weight %, 0.05 weight %, or 0.01 weight %. In some insitu conversion process embodiments, the in situ conversion process mayresult in no, or substantially no, asphaltene production, especially ifinitial production from the formation is inhibited or if initialproduction is ignored until the formation produces hydrocarbons of aminimum quality.

[1244] Condensable hydrocarbons of a produced fluid may includerelatively large amounts of cycloalkanes. Linear chain molecules mayform ring compounds (e.g., hexane may form cyclohexane) in theformation. In addition, some aromatic compounds may be hydrogenated inthe formation to produce cycloalkanes (e.g., benzene may be hydrogenatedto form cyclohexane). The condensable hydrocarbons may include acycloalkane component of from about 0 weight % to about 30 weight %. Insome in situ conversion process embodiments, the condensablehydrocarbons may include a cycloalkane component from about 1% to about20%, or from about 5% to about 20%.

[1245] In certain in situ conversion process embodiments, thecondensable hydrocarbons of a fluid produced from a formation mayinclude compounds containing nitrogen. For example, less than about 1weight % (when calculated on an elemental basis) of the condensablehydrocarbons may be nitrogen (e.g., typically the nitrogen may be innitrogen containing compounds such as pyridines, amines, amides,carbazoles, etc.). The amount of nitrogen containing compounds maydepend on the amount of nitrogen in the initial hydrocarbon materialpresent in the formation.

[1246] Some of the nitrogen in the initial hydrocarbon material presentmay be produced as ammonia. Produced ammonia may be separated fromhydrocarbons. The ammonia may be separated, along with water, fromformation fluid produced from the formation. Formation fluid producedfrom the formation may include about 0.05 weight % or more of ammonia.Certain formations may produce larger amounts of ammonia (e.g., up toabout 10 weight % of the total fluid produced may be ammonia).

[1247] In certain in situ conversion process embodiments, thecondensable hydrocarbons of a fluid produced from a formation mayinclude compounds containing oxygen. For example, in certain embodiments(e.g., for oil shale and heavy hydrocarbons), less than about 1 weight %(when calculated on an elemental basis) of the condensable hydrocarbonsmay be oxygen containing compounds (e.g., typically the oxygen may be inoxygen containing compounds such as phenol, substituted phenols,ketones, etc.). In some in situ conversion process embodiments, betweenabout 1 weight % and about 30 weight % of the condensable hydrocarbonsmay typically include oxygen containing compounds such as phenols,substituted phenols, ketones, etc. In some instances, certain compoundscontaining oxygen (e.g., phenols) may be valuable and, as such, may beeconomically separated from the produced fluid. Other types offormations may contain insignificant or no oxygen containing compoundsin the initial hydrocarbon material. Such formations may not produce anyor only insignificant amounts of oxygenated compounds. Some of theoxygen in the initial hydrocarbon material may be produced as carbondioxide.

[1248] In some in situ conversion process embodiments, condensablehydrocarbons of the fluid produced from a formation may includecompounds containing sulfur. For example, less than about 1 weight %(when calculated on an elemental basis) of the condensable hydrocarbonsmay be sulfur containing compounds. Typical sulfur containing compoundsmay include compounds such as thiophenes, mercaptans, etc. The amount ofsulfur containing compounds may depend on the amount of sulfur in theinitial hydrocarbon material present in the formation. Some of thesulfur in the initial hydrocarbon material present may be produced ashydrogen sulfide.

[1249] In some in situ conversion process embodiments, formation fluidproduced from the formation may include molecular hydrogen (H₂).Hydrogen may be from about 0.1 volume % to about 80 volume % of anon-condensable component of formation fluid produced from theformation. In some in situ conversion process embodiments, H₂ may beabout 5 volume % to about 70 volume % of the non-condensable componentof formation fluid produced from the formation. The amount of hydrogenin the formation fluid may be strongly dependent on the temperature ofthe formation. A high formation temperature may result in the productionof significant amounts of hydrogen. A high temperature may also resultin the formation of a significant amount of coke within the formation.

[1250] In some in situ conversion process embodiments, a large portionof the total organic carbon content of a formation may be converted intohydrocarbon fluids. In some embodiments, up to about 20 weight % of thetotal organic carbon content of hydrocarbons in the portion may betransformed into hydrocarbon fluids. In some in situ conversion processembodiments, the weight percentage of total organic carbon content ofhydrocarbons in the portion removed during the in situ process may besignificantly increased if synthesis gas is generated within theportion.

[1251] A total potential amount of products that may be produced fromhydrocarbons may be determined by a Fischer Assay. A Fischer Assay is astandard method that involves heating a sample of hydrocarbons toapproximately 500° C. in one hour, collecting products produced from theheated sample, and quantifying the products. In an embodiment, a methodfor treating an oil shale formation in situ may include heating asection of the formation to yield greater than about 60 weight % of thepotential amount of products from the hydrocarbons as measured by theFischer Assay.

[1252] In certain embodiments, heating of the selected section of theformation may be controlled to pyrolyze at least about 20 weight % (orin some embodiments about 25 weight %) of the hydrocarbons within theselected section of the formation. Conversion of selected portions ofhydrocarbon layers within a formation may be avoided to inhibitsubsidence of the formation.

[1253] Heating at least a portion of a formation may cause some of thehydrocarbons within the portion to pyrolyze. Pyrolyzation may generatehydrocarbon fragments. The hydrocarbon fragments may be reactive and mayreact with other compounds in the formation and/or with otherhydrocarbon fragments produced by pyrolysis. Reaction of the hydrocarbonfragments with other compounds and/or with each other, however, mayreduce production of a selected product. A reducing agent in, orprovided to, the portion of the formation during heating may increaseproduction of the selected product. The reducing agent may be, but isnot limited to, H₂, methane, and/or other non-condensable hydrocarbonfluids.

[1254] In an in situ conversion process embodiment, molecular hydrogenmay be provided to the formation to create a reducing environment.Hydrogenation reactions between the molecular hydrogen and some of thehydrocarbons within a portion of the formation may generate heat. Theheat may heat the portion of the formation. Molecular hydrogen may alsobe generated within the portion of the formation. The generated H₂ mayhydrogenate hydrocarbon fluids within a portion of a formation. Thehydrogenation may generate heat that transfers to the formation tomaintain a desired temperature within the formation.

[1255] H₂ may be produced from a first portion of an oil shaleformation. The H₂ may be separated from formation fluid produced fromthe first portion. The H₂ from the first portion, along with otherreducing or substantially inert fluid (e.g., methane, ethane, and/ornitrogen), may be provided to a second portion of the formation tocreate a reducing environment within the second portion. The secondportion of the formation may be heated by heat sources. Power input intothe heat sources may be reduced after introduction of H₂ due to heatingof the formation by hydrogenation reactions within the formation. H₂ maybe introduced into the formation continuously or batchwise.

[1256] Hydrogen introduced into the second portion of the formation mayreduce (e.g., at least partially saturate) some pyrolyzation fluid beingproduced or present in the second section. Reducing the pyrolyzationfluid may decrease a concentration of olefins in the pyrolyzationfluids. Reducing the pyrolysis products may improve the product qualityof the hydrocarbon fluids.

[1257] An in situ conversion process may generate significant amounts ofH₂ and hydrocarbon fluids within the formation. Generation of hydrogenwithin the formation, and pressure within the formation sufficient toforce hydrogen into a liquid phase within the formation, may produce areducing environment within the formation without the need to introducea reducing fluid (e.g., H₂ and/or non-condensable saturatedhydrocarbons) into the formation. A hydrogen component of formationfluid produced from the formation may be separated and used for desiredpurposes. The desired purposes may include, but are not limited to, fuelfor fuel cells, fuel for combustors, and/or a feed stream for surfacehydrogenation units.

[1258] In an in situ conversion process embodiment, heating theformation may result in an increase in the thermal conductivity of aselected section of the heated portion. For example, porosity andpermeability within a selected section of the portion may increasesubstantially during heating such that heat may be transferred throughthe formation not only by conduction, but also by convection and/or byradiation from a heat source. Such radiant and convective transfer ofheat may increase an apparent thermal conductivity of the selectedsection and, consequently, the thermal diffusivity. The large apparentthermal diffusivity may make heating at least a portion of an oil shaleformation from heat sources feasible. For example, a combination ofconductive, radiant, and/or convective heating may accelerate heating.Such accelerated heating may significantly decrease a time required forproducing hydrocarbons and may significantly increase the economicfeasibility of commercialization of the in situ conversion process.

[1259] Thermal conductivity and thermal diffusivity within an oil shaleformation may vary depending on, for example, a density of the oil shaleformation, a heat capacity of the formation, and a thermal conductivityof the formation. As pyrolysis occurs within a selected section, aportion of hydrocarbon containing mass may be removed from the selectedsection. The removal of mass may include, but is not limited to, removalof water and a transformation of hydrocarbons to formation fluids. Alower thermal conductivity may be expected as water is removed from anoil shale formation. Reduction of thermal conductivity may be a functionof depth of hydrocarbons in the formation. Lithostatic pressure mayincrease with depth. Deep in a formation, lithostatic pressure may closecertain types of openings (e.g., cleats and/or fractures) in theformation. The closure of the formation openings may result in adecreased or minimal effect of mass removal from the formation onthermal conductivity and thermal diffusivity.

[1260] In some in situ conversion process embodiments, the in situconversion process may generate molecular hydrogen during the pyrolysisprocess. In addition, pyrolysis tends to increase the porosity/voidspaces in the formation. Void spaces in the formation may containhydrogen gas generated by the pyrolysis process. Hydrogen gas may haveabout six times the thermal conductivity of nitrogen or air. Thepresence of hydrogen in void spaces may raise the thermal conductivityof the formation and decrease the effect of mass removal from theformation on thermal conductivity.

[1261] Some in situ conversion process embodiments may be able toeconomically treat formations that were previously believed to beuneconomical to produce. Recovery of hydrocarbons from previouslyuneconomically producible formations may be possible because of thesurprising increases in thermal conductivity and thermal diffusivitythat can be achieved during thermal conversion of hydrocarbons withinthe formation by conductively and/or radiatively heating a portion ofthe formation. Surprising results are illustrated by the fact that priorliterature indicated that certain oil shale formations exhibitedrelatively low values for thermal conductivity and thermal diffusivitywhen heated. For example, in government report No. 8364 by J. M. Singerand R. P. Tye entitled “Thermal, Mechanical, and Physical Properties ofSelected Bituminous Coals and Cokes,” U.S. Department of the Interior,Bureau of Mines (1979), the authors report the thermal conductivity andthermal diffusivity for four bituminous coals. This government reportincludes graphs of thermal conductivity and diffusivity that showrelatively low values up to about 400° C. (e.g., thermal conductivity isabout 0.2 W/(m° C.) or below, and thermal diffusivity is below about1.7×10⁻³ cm²/s). This government report states: “coals and cokes areexcellent thermal insulators.”

[1262] In an in situ conversion process embodiment, heating a portion ofan oil shale formation in situ to a temperature less than an upperpyrolysis temperature may increase permeability of the heated portion.Permeability may increase due to formation of thermal fractures withinthe heated portion. Thermal fractures may be generated by thermalexpansion of the formation and/or by localized increases in pressure dueto vaporization of liquids (e.g., water and/or hydrocarbons) in theformation. As a temperature of the heated portion increases, water inthe formation may be vaporized. The vaporized water may escape and/or beremoved from the formation. Removal of water may also increase thepermeability of the heated portion. In addition, permeability of theheated portion may also increase as a result of mass loss from theformation due to generation of pyrolysis fluids in the formation.Pyrolysis fluid may be removed from the formation through productionwells.

[1263] Heating the formation from heat sources placed in the formationmay allow a permeability of the heated portion of an oil shale formationto be substantially uniform. A substantially uniform permeability mayinhibit channeling of formation fluids in the formation and allowproduction from substantially all portions of the heated formation. Anassessed (e.g., calculated or estimated) permeability of any selectedportion in the formation having a substantially uniform permeability maynot vary by more than a factor of 10 from an assessed averagepermeability of the selected portion.

[1264] Permeability of a selected section within the heated portion ofthe oil shale formation may rapidly increase when the selected sectionis heated by conduction. A permeability of an impermeable oil shaleformation may be less than about 0.1 millidarcy (9.9×10⁻¹⁷ m²) beforetreatment. In some embodiments, pyrolyzing at least a portion of an oilshale formation may increase a permeability within a selected section ofthe portion to greater than about 10 millidarcy, 100 millidarcy, 1darcy, 10 darcy, 20 darcy, or 50 darcy. A permeability of a selectedsection of the portion may increase by a factor of more than about 100,1,000, 10,000, 100,000 or more.

[1265] In some in situ conversion process embodiments, superposition(e.g., overlapping influence) of heat from one or more heat sources mayresult in substantially uniform heating of a portion of an oil shaleformation. Since formations during heating will typically have atemperature gradient that is highest near heat sources and reduces withincreasing distance from the heat sources, “substantially uniform”heating means heating such that temperature in a majority of the sectiondoes not vary by more than 100° C. from an assessed average temperaturein the majority of the selected section (volume) being treated.

[1266] Removal of hydrocarbons from the formation during an in situconversion process may occur on a microscopic scale, as well as amacroscopic scale (e.g., through production wells). Hydrocarbons may beremoved from micropores within a portion of the formation due toheating. Micropores may be generally defined as pores having across-sectional dimension of less than about 1000 Å. Removal of solidhydrocarbons may result in a substantially uniform increase in porositywithin at least a selected section of the heated portion. Heating theportion of an oil shale formation may substantially uniformly increase aporosity of a selected section within the heated portion. “Substantiallyuniform porosity” means that the assessed (e.g., calculated orestimated) porosity of any selected portion in the formation does notvary by more than about 25% from the assessed average porosity of suchselected portion.

[1267] Physical characteristics of a portion of an oil shale formationafter pyrolysis may be similar to those of a porous bed. The physicalcharacteristics of a formation subjected to an in situ conversionprocess may significantly differ from physical characteristics of an oilshale formation subjected to injection of gases that burn hydrocarbonsto heat the hydrocarbons and or to formations subjected to steam floodproduction. Gases injected into virgin or fractured formations maychannel through the formation. The gases may not be uniformlydistributed throughout the formation. In contrast, a gas injected into aportion of an oil shale formation subjected to an in situ conversionprocess may readily and substantially uniformly contact the carbonand/or hydrocarbons remaining in the formation. Gases produced byheating the hydrocarbons may be transferred a significant distancewithin the heated portion of the formation with minimal pressure loss.

[1268] Transfer of gases in a formation over significant distances maybe particularly advantageous to reduce the number of production wellsneeded to produce formation fluid from the formation. A first portion ofan oil shale formation may be subjected to an in situ conversionprocess. The volume of the formation subjected to in situ conversion maybe expanded by heating abutting portions of the oil shale formation.Formation fluid produced in the abutting portions of the formation maybe produced from production wells in the first portion. If needed, a fewadditional production wells may be installed in the abutting portions offormation, but such production wells may have large separationdistances. The ability to transfer fluid in a formation over longdistances may be advantageous for treating a steeply dipping oil shaleformation. Production wells may be placed in an upper portion of thedipping hydrocarbon production. Heat sources may be inserted into thesteeply dipping formation. The heat sources may follow the dip of theformation. The upper portion may be subjected to thermal treatment byactivating portions of the heat sources in the upper portion. Abuttingportions of the steeply dipping formation may be subjected to thermaltreatment after treatment in the upper portion increases thepermeability of the formation so that fluids in lower portions may beproduced from the upper portions.

[1269] Synthesis gas may be produced from a portion of an oil shaleformation. Synthesis gas may be produced from oil shale. The oil shaleformation may be heated prior to synthesis gas generation to produce asubstantially uniform, relatively high permeability formation. In an insitu conversion process embodiment, synthesis gas production may becommenced after production of pyrolysis fluids has been exhausted orbecomes uneconomical. Alternately, synthesis gas generation may becommenced before substantial exhaustion or uneconomical pyrolysis fluidproduction has been achieved if production of synthesis gas will be moreeconomically favorable. Formation temperatures will usually be higherthan pyrolysis temperatures during synthesis gas generation. Raising theformation temperature from pyrolysis temperatures to synthesis gasgeneration temperatures allows further utilization of heat applied tothe formation to pyrolyze the formation. While raising a temperature ofa formation from pyrolysis temperatures to synthesis gas temperatures,methane and/or H₂ may be produced from the formation.

[1270] Producing synthesis gas from a formation from which pyrolyzationfluids have been previously removed allows a synthesis gas to beproduced that includes mostly H₂, CO, water, and/or CO₂. Producedsynthesis gas, in certain embodiments, may have substantially nohydrocarbon component unless a separate source hydrocarbon stream isintroduced into the formation with or in addition to the synthesis gasproducing fluid. Producing synthesis gas from a substantially uniform,relatively high permeability formation that was formed by slowly heatinga formation through pyrolysis temperatures may allow for easyintroduction of a synthesis gas generating fluid into the formation, andmay allow the synthesis gas generating fluid to contact a relativelylarge portion of the formation. The synthesis gas generating fluid cando so because the permeability of the formation has been increasedduring pyrolysis and/or because the surface area per volume in theformation has increased during pyrolysis. The relatively large surfacearea (e.g., “contact area”) in the post-pyrolysis formation tends toallow synthesis gas generating reactions to be substantially atequilibrium conditions for C, H₂, CO, water, and CO₂. Reactions in whichmethane is formed may, however, not be at equilibrium because they arekinetically limited. The relatively high, substantially uniformformation permeability may allow production wells to be spaced fartherapart than production wells used during pyrolysis of the formation.

[1271] A temperature of at least a portion of a formation that is usedto generate synthesis gas may be raised to a synthesis gas generatingtemperature (e.g., between about 400° C. and about 1200° C.). In someembodiments, composition of produced synthesis gas may be affected byformation temperature, by the temperature of the formation adjacent tosynthesis gas production wells, and/or by residence time of thesynthesis gas components. A relatively low synthesis gas generationtemperature may produce a synthesis gas having a high H₂ to CO ratio,but the produced synthesis gas may also include a large portion of othergases such as water, CO₂, and methane. A relatively high formationtemperature may produce a synthesis gas having a H₂ to CO ratio thatapproaches 1, and the stream may include mostly and, in some cases, onlyH₂ and CO. If the synthesis gas generating fluid is substantially puresteam, then the H₂ to CO ratio may approach 1 at relatively hightemperatures. At a formation temperature of about 700° C., the formationmay produce a synthesis gas with a H₂ to CO ratio of about 2 at acertain pressure. The composition of the synthesis gas tends to dependon the nature of the synthesis gas generating fluid.

[1272] Synthesis gas generation is generally an endothermic process.Heat may be added to a portion of a formation during synthesis gasproduction to keep formation temperature at a desired synthesis gasgenerating temperature or above a minimum synthesis gas generatingtemperature. Heat may be added to the formation from heat sources, fromoxidation reactions within the portion, and/or from introducingsynthesis gas generating fluid into the formation at a highertemperature than the temperature of the formation.

[1273] An oxidant may be introduced into a portion of the formation withsynthesis gas generating fluid. The oxidant may exothermically reactwith carbon within the portion of the formation to heat the formation.Oxidation of carbon within a formation may allow a portion of aformation to be economically heated to relatively high synthesis gasgenerating temperatures. The oxidant may be introduced into theformation without synthesis gas generating fluid to heat the portion.Using an oxidant, or an oxidant and heat sources, to heat the portion ofthe formation may be significantly more favorable than heating theportion of the formation with only the heat sources. The oxidant may be,but is not limited to, air, oxygen, or oxygen enriched air. The oxidantmay react with carbon in the formation to produce CO₂ and/or CO. The useof air, or oxygen enriched air (i.e., air with an oxygen content greaterthan 21 volume %), to generate heat within the formation may cause asignificant portion of N₂ to be present in produced synthesis gas.Temperatures in the formation may be maintained below temperaturesneeded to generate oxides of nitrogen (NO_(x)), so that little or noNO_(x) compounds may be present in produced synthesis gas.

[1274] A mixture of steam and oxygen, steam and enriched air, or steamand air, may be continuously injected into a formation. If injection ofsteam and oxygen or steam and enriched air is used for synthesis gasproduction, the oxygen may be produced on site (or near to the site) byelectrolysis of water utilizing direct current output of a fuel cell. H₂produced by the electrolysis of water may be used as a fuel stream forthe fuel cell. O₂ produced by the electrolysis of water may also beinjected into the hot formation to raise a temperature of the formation.

[1275] Heat sources and/or production wells within a formation forpyrolyzing and producing pyrolysis fluids from the formation may beutilized for different purposes during synthesis gas production. A wellthat was used as a heat source or a production well during pyrolysis maybe used as an injection well to introduce synthesis gas producing fluidinto the formation. A well that was used as a heat source or aproduction well during pyrolysis may be used as a production well duringsynthesis gas generation. A well that was used as a heat source or aproduction well during pyrolysis may be used as a heat source to heatthe formation during synthesis gas generation. Some production wellsused during a pyrolysis phase may be shut in. Synthesis gas productionwells may be spaced further apart than pyrolysis production wellsbecause of the relatively high, substantially uniform permeability ofthe formation. Some production wells used during a pyrolysis phase maybe shut in or converted to other uses. Synthesis gas production wellsmay be heated to relatively high temperatures so that a portion of theformation adjacent to the production well is at a temperature that willproduce a desired synthesis gas composition. Comparatively, pyrolysisfluid production wells may not be heated at all, or may only be heatedto a temperature that will inhibit condensation of pyrolysis fluidwithin the production well.

[1276] Synthesis gas may be produced from a dipping formation from wellsused during pyrolysis of the formation. As shown in FIG. 9, synthesisgas production wells 206 may be located above and down dip frominjection well 202. Hot synthesis gas producing fluid may be introducedinto injection well 202. Hot synthesis gas fluid that moves down dip maygenerate synthesis gas that is produced through synthesis gas productionwells 206. Synthesis gas generating fluid that moves up dip may generatesynthesis gas in a portion of the formation that is at synthesis gasgenerating temperatures. A portion of the synthesis gas generating fluidand generated synthesis gas that moves up dip above the portion of theformation at synthesis gas generating temperatures may heat adjacentportions of the formation. The synthesis gas generating fluid that movesup dip may condense, heat adjacent portions of formation, and flowdownwards towards or into a portion of the formation at synthesis gasgenerating temperature. The synthesis gas generating fluid may thengenerate additional synthesis gas.

[1277] Synthesis gas generating fluid may be any fluid capable ofgenerating H₂ and CO within a heated portion of a formation. Synthesisgas generating fluid may include water, O₂, air, CO₂, hydrocarbonfluids, or combinations thereof. Water may be introduced into aformation as a liquid or as steam. Water may react with carbon in aformation to produce H₂, CO, and CO₂. CO₂ may react with hot carbon toform CO. Air and O₂ may be oxidants that react with carbon in aformation to generate heat and form CO₂, CO, and other compounds.Hydrocarbon fluids may react within a formation to form H₂, CO, CO₂,H₂O, coke, methane, and/or other light hydrocarbons. Introducing lowcarbon number hydrocarbons (i.e., compounds with carbon numbers lessthan 5) may produce additional H₂ within the formation. Adding highercarbon number hydrocarbons to the formation may increase an energycontent of generated synthesis gas by having a significant methane andother low carbon number compounds fraction within the synthesis gas.

[1278] Water provided as a synthesis gas generating fluid may be derivedfrom numerous different sources. Water may be produced during apyrolysis stage of treating a formation. The water may include someentrained hydrocarbon fluids. Such fluid may be used as synthesis gasgenerating fluid. Water that includes hydrocarbons may advantageouslygenerate additional H₂ when used as a synthesis gas generating fluid.Water produced from water pumps that inhibit water flow into a portionof formation being subjected to an in situ conversion process mayprovide water for synthesis gas generation. A low rank kerogen resourceor hydrocarbons having a relatively high water content (i.e., greaterthan about 20 weight % H₂O) may generate a large amount of water and/orCO₂ if subjected to an in situ conversion process. The water and CO₂produced by subjecting a low rank kerogen resource to an in situconversion process may be used as a synthesis gas generating fluid.

[1279] Reactions involved in the formation of synthesis gas may include,but are not limited to:

C+H₂O

H₂+CO  (43)

C+2H₂O

2H₂+CO₂  (44)

C+CO₂

2CO  (45)

[1280] Thermodynamics also allows the following reactions to proceed:

2C+2H₂O

CH₄+CO₂  (46)

C+2H₂

CH₄  (47)

[1281] However, kinetics of the reactions are slow in certainembodiments, so that relatively low amounts of methane are formed atformation conditions from Reactions 46 and 47.

[1282] In the presence of oxygen, the following reaction may take placeto generate carbon dioxide and heat:

C+O₂→CO₂  (48)

[1283] Equilibrium gas phase compositions of hydrocarbons in contactwith steam may provide an indication of the compositions of componentsproduced in a formation during synthesis gas generation. Equilibriumcomposition data for H₂, carbon monoxide, and carbon dioxide may be usedto determine appropriate operating conditions (e.g., temperature) thatmay be used to produce a synthesis gas having a selected composition.Equilibrium conditions may be approached within a formation due to ahigh, substantially uniform permeability of the formation. Compositiondata obtained from synthesis gas production may in many in situconversion process embodiments, deviate by less than 10% fromequilibrium values.

[1284] In one synthesis gas production embodiment, a composition of theproduced synthesis gas can be changed by injecting additional componentsinto the formation along with steam. Carbon dioxide may be provided inthe synthesis gas generating fluid to inhibit production of carbondioxide from the formation during synthesis gas generation. The carbondioxide may shift the equilibrium of Reaction 44 to the left, thusreducing the amount of carbon dioxide generated from formation carbon.The carbon dioxide may also shift the equilibrium of Reaction 45 to theright to generate carbon monoxide. Carbon dioxide may be separated fromthe synthesis gas and may be re-injected into the formation with thesynthesis gas generating fluid. Addition of carbon dioxide in thesynthesis gas generating fluid may, however, reduce the production ofhydrogen.

[1285]FIG. 117 depicts a schematic diagram of use of water recoveredfrom pyrolysis fluid production to generate synthesis gas. Heat source801 with electric heater 803 produces pyrolysis fluid 807 from firstsection 805 of the formation. Produced pyrolysis fluid 807 may be sentto separator 809. Separator 809 may include a number of individualseparation units and processing units that produce aqueous stream 811,vapor stream 813, and hydrocarbon condensate stream 815. Aqueous stream811 from separator 809 may be combined with synthesis gas generatingfluid 818 to form synthesis gas generating fluid 821. Synthesis gasgenerating fluid 821 may be provided to injection well 817 andintroduced to second portion 819 of the formation. Synthesis gas 823 maybe produced from synthesis gas production well 825.

[1286]FIG. 118 depicts a schematic diagram of an embodiment of a systemfor synthesis gas production. Synthesis gas 830 may be produced fromformation 832 through production well 834. Gas separation unit 836 mayseparate a portion of carbon dioxide from synthesis gas 830 to produceCO₂ stream 838 and remaining synthesis gas stream 840. CO₂ stream 838may be mixed with synthesis gas producing fluid stream 842 that isintroduced into formation 832 through injection well 837. In somesynthesis gas process embodiments, CO₂ may be introduced into theformation separate from synthesis gas producing fluid. Introducing CO₂may inhibit conversion of carbon within the formation to CO₂ and/or mayincrease an amount of CO generated within the formation.

[1287] Synthesis gas generating fluid may be introduced into a formationin a variety of different ways. Steam may be injected into a heated oilshale formation at a lowermost portion of the heated formation.Alternatively, in a steeply dipping formation, steam may be injected updip with synthesis gas production down dip. The injected steam may passthrough the remaining oil shale formation to a production well. Inaddition, endothermic heat of reaction may be provided to the formationwith heat sources disposed along a path of the injected steam. Inalternate embodiments, steam may be injected at a plurality of locationsalong the oil shale formation to increase penetration of the steamthroughout the formation. A line drive pattern of locations may also beutilized. The line drive pattern may include alternating rows of steaminjection wells and synthesis gas production wells.

[1288] Synthesis gas reactions may be slow at relatively low pressuresand at temperatures below about 400° C. At relatively low pressures, andtemperatures between about 400° C. and about 700° C., Reaction 44 maypredominate so that synthesis gas composition is primarily hydrogen andcarbon dioxide. At relatively low pressures and temperatures greaterthan about 700° C., Reaction 43 may predominate so that synthesis gascomposition is primarily hydrogen and carbon monoxide.

[1289] Advantages of a lower temperature synthesis gas reaction mayinclude lower heat requirements, cheaper metallurgy, and lessendothermic reactions (especially when methane formation takes place).An advantage of a higher temperature synthesis gas reaction is thathydrogen and carbon monoxide may be used as feedstock for otherprocesses (e.g., Fischer-Tropsch processes).

[1290] A pressure of the oil shale formation may be maintained atrelatively high pressures during synthesis gas production. The pressuremay range from atmospheric pressure to a pressure that approaches alithostatic pressure of the formation. Higher formation pressures mayallow generation of electricity by passing produced synthesis gasthrough a turbine. Higher formation pressures may allow for smallercollection conduits to transport produced synthesis gas and reduceddownstream compression requirements on the surface.

[1291] In some synthesis gas process embodiments, synthesis gas may beproduced from a portion of a formation in a substantially continuousmanner. The portion may be heated to a desired synthesis gas generatingtemperature. A synthesis gas generating fluid may be introduced into theportion. Heat may be added to, or generated within, the portion of theformation during introduction of the synthesis gas generating fluid tothe portion. The added heat may compensate for the loss of heat due tothe endothermic synthesis gas reactions as well as heat losses to a toplayer (overburden), bottom layer (underburden), and unreactive materialin the portion.

[1292]FIG. 119 illustrates a schematic representation of an embodimentof a continuous synthesis gas production system. FIG. 119 includes aformation with heat injection wellbore 850 and heat injection wellbore852. The wellbores may be members of a larger pattern of wellboresplaced throughout a portion of the formation. The portion of theformation may be heated to synthesis gas generating temperatures byheating the formation with heat sources, by injecting an oxidizingfluid, or by a combination thereof. Oxidizing fluid 854 (e.g., air,enriched air, or oxygen) and synthesis gas generating fluid 856 (e.g.,water, or steam) may be injected into wellbore 850. In a synthesis gasprocess embodiment that uses oxygen and steam, the ratio of oxygen tosteam may range from approximately 1:2 to approximately 1:10, orapproximately 1:3 to approximately 1:7 (e.g., about 1:4).

[1293] In situ combustion of hydrocarbons may heat region 858 of theformation between wellbores 850 and 852. Injection of the oxidizingfluid may heat region 858 to a particular temperature range, forexample, between about 600° C. and about 700° C. The temperature mayvary, however, depending on a desired composition of the synthesis gas.An advantage of the continuous production method may be that atemperature gradient established across region 858 may be substantiallyuniform and substantially constant with time once the formationapproaches thermal equilibrium. Continuous production may also eliminatea need for use of valves to reverse injection directions on a frequentbasis. Further, continuous production may reduce temperatures near theinjection wells due to endothermic cooling from the synthesis gasreaction that occur in the same region as oxidative heating. Thesubstantially constant temperature gradient may allow for control ofsynthesis gas composition. Produced synthesis gas 860 may exitcontinuously from wellbore 852.

[1294] In a synthesis gas process embodiment, oxygen may be used insteadof air as oxidizing fluid 854 in continuous production. If air is used,nitrogen may need to be separated from the produced synthesis gas. Theuse of oxygen as oxidizing fluid 854 may increase a cost of productiondue to the cost of obtaining substantially pure oxygen. The cryogenicnitrogen by-product obtained from an air separation plant used toproduce the required oxygen may, however, be used in a heat exchanger tocondense hydrocarbons from a hot vapor stream produced during pyrolysisof hydrocarbons. The pure nitrogen may also be used for ammoniaproduction.

[1295] In some synthesis gas process embodiments, synthesis gas may beproduced in a batch manner from a portion of the formation. The portionof the formation may be heated, or heat may be generated within theportion, to raise a temperature of the portion to a high synthesis gasgenerating temperature. Synthesis gas generating fluid may then be addedto the portion until generation of synthesis gas reduces the temperatureof the formation below a temperature that produces a desired synthesisgas composition. Introduction of the synthesis gas generating fluid maythen be stopped. The cycle may be repeated by reheating the portion ofthe formation to the high synthesis gas generating temperature andadding synthesis gas generating fluid after obtaining the high synthesisgas generating temperature. Composition of generated synthesis gas maybe monitored to determine when addition of synthesis gas generatingfluid to the formation should be stopped.

[1296]FIG. 120 illustrates a schematic representation of an embodimentof a batch production of synthesis gas in an oil shale formation.Wellbore 870 and wellbore 872 may be located within a portion of theformation. The wellbores may be members of a larger pattern of wellboresthroughout the portion of the formation. Oxidizing fluid 874, such asair or oxygen, may be injected into wellbore 870. Oxidation ofhydrocarbons may heat region 876 of a formation between wellbores 870and 872. Injection of air or oxygen may continue until an averagetemperature of region 876 is at a desired temperature (e.g., betweenabout 900° C. and about 1000° C.). Higher or lower temperatures may alsobe developed. A temperature gradient may be formed in region 876 betweenwellbore 870 and wellbore 872. The highest temperature of the gradientmay be located proximate injection wellbore 870.

[1297] When a desired temperature has been reached, or when oxidizingfluid has been injected for a desired period of time, oxidizing fluidinjection may be lessened and/or ceased. Synthesis gas generating fluid877, such as steam or water, may be injected into injection wellbore 872to produce synthesis gas. A back pressure of the injected steam or waterin the injection wellbore may force the synthesis gas produced andun-reacted steam across region 876. A decrease in average temperature ofregion 876 caused by the endothermic synthesis gas reaction may bepartially offset by the temperature gradient in region 876 in adirection indicated by arrow 878. Product stream 880 may be producedthrough heat source wellbore 870. If the composition of the productdeviates from a desired composition, then steam injection may cease, andair or oxygen injection may be reinitiated.

[1298] Synthesis gas of a selected composition may be produced byblending synthesis gas produced from different portions of theformation. A first portion of a formation may be heated by one or moreheat sources to a first temperature sufficient to allow generation ofsynthesis gas having a H₂ to carbon monoxide ratio of less than theselected H₂ to carbon monoxide ratio (e.g., about 1:1 or 2:1). A firstsynthesis gas generating fluid may be provided to the first portion togenerate a first synthesis gas. The first synthesis gas may be producedfrom the formation. A second portion of the formation may be heated byone or more heat sources to a second temperature sufficient to allowgeneration of synthesis gas having a H₂ to carbon monoxide ratio ofgreater than the selected H₂ to carbon monoxide ratio (e.g., a ratio of3:1 or more). A second synthesis gas generating fluid may be provided tothe second portion to generate a second synthesis gas. The secondsynthesis gas may be produced from the formation. The first synthesisgas may be blended with the second synthesis gas to produce a blendsynthesis gas having a desired H₂ to carbon monoxide ratio.

[1299] The first temperature may be different than the secondtemperature. Alternatively, the first and second temperatures may beapproximately the same temperature. For example, a temperaturesufficient to allow generation of synthesis gas having differentcompositions may vary depending on compositions of the first and secondportions and/or prior pyrolysis of hydrocarbons within the first andsecond portions. The first synthesis gas generating fluid may havesubstantially the same composition as the second synthesis gasgenerating fluid. Alternatively, the first synthesis gas generatingfluid may have a different composition than the second synthesis gasgenerating fluid. Appropriate first and second synthesis gas generatingfluids may vary depending upon, for example, temperatures of the firstand second portions, compositions of the first and second portions, andprior pyrolysis of hydrocarbons within the first and second portions.

[1300] In addition, synthesis gas having a selected ratio of H₂ tocarbon monoxide may be obtained by controlling the temperature of theformation. In one embodiment, the temperature of an entire portion orsection of the formation may be controlled to yield synthesis gas with aselected ratio. Alternatively, the temperature in or proximate asynthesis gas production well may be controlled to yield synthesis gaswith the selected ratio. Controlling temperature near a production wellmay be sufficient because synthesis gas reactions may be fast enough toallow reactants and products to approach equilibrium concentrations.

[1301] In a synthesis gas process, synthesis gas having a selected ratioof H₂ to carbon monoxide may be obtained by treating produced synthesisgas at the surface. First, the temperature of the formation may becontrolled to yield synthesis gas with a ratio different than a selectedratio. For example, the formation may be maintained at a relatively hightemperature to generate a synthesis gas with a relatively low H₂ tocarbon monoxide ratio (e.g., the ratio may approach 1 under certainconditions). Some or all of the produced synthesis gas may then beprovided to a shift reactor (shift process) at the surface. Carbonmonoxide reacts with water in the shift process to produce H₂ and carbondioxide. Therefore, the shift process increases the H₂ to carbonmonoxide ratio. The carbon dioxide may then be separated to obtain asynthesis gas having a selected H₂ to carbon monoxide ratio.

[1302] Produced synthesis gas 918 may be used for production of energy.In FIG. 121, treated gases 920 may be routed from treatment section 900to energy generation unit 902 for extraction of useful energy. In someembodiments, energy may be extracted from the combustible gases in thesynthesis gas by oxidizing the gases to produce heat and converting aportion of the heat into mechanical and/or electrical energy.Alternatively, energy generation unit 902 may include a fuel cell thatproduces electrical energy. In addition, energy generation unit 902 mayinclude, for example, a molten carbonate fuel cell or another type offuel cell, a turbine, a boiler firebox, or a downhole gas heater.Produced electrical energy 904 may be supplied to power grid 906. Aportion of produced electricity 908 may be used to supply energy toelectrical heating elements 910 that heat formation 912.

[1303] In one embodiment, energy generation unit 902 may be a boilerfirebox. A firebox may include a small refractory-lined chamber, builtwholly or partly in the wall of a kiln, for combustion of fuel. Air oroxygen 914 may be supplied to energy generation unit 902 to oxidize theproduced synthesis gas. Water 916 produced by oxidation of the synthesisgas may be recycled to the formation to produce additional synthesisgas.

[1304] A portion of synthesis gas produced from a formation may, in someembodiments, be used for fuel in downhole gas heaters. Downhole gasheaters (e.g., flameless combustors, downhole combustors, etc.) may beused to provide heat to an oil shale formation. In some embodiments,downhole gas heaters may heat portions of a formation substantially byconduction of heat through the formation. Providing heat from gasheaters may be primarily self-reliant and may reduce or eliminate a needfor electric heaters. Because downhole gas heaters may have thermalefficiencies approaching 90%, the amount of carbon dioxide released tothe environment by downhole gas heaters may be less than the amount ofcarbon dioxide released to the environment from a process usingfossil-fuel generated electricity to heat the oil shale formation.

[1305] Carbon dioxide may be produced during pyrolysis and/or duringsynthesis gas generation. Carbon dioxide may also be produced by energygeneration processes and/or combustion processes. Net release of carbondioxide to the atmosphere from an in situ conversion process forhydrocarbons may be reduced by utilizing the produced carbon dioxideand/or by storing carbon dioxide within the formation or within anotherformation. For example, a portion of carbon dioxide produced from theformation may be utilized as a flooding agent or as a feedstock forproducing chemicals.

[1306] In an in situ conversion process embodiment, an energy generationprocess may produce a reduced amount of emissions by sequestering carbondioxide produced during extraction of useful energy. For example,emissions from an energy generation process may be reduced by storingcarbon dioxide within an oil shale formation. In an in situ conversionprocess embodiment, the amount of stored carbon dioxide may beapproximately equivalent to that in an exit stream from the formation.

[1307]FIG. 121 illustrates a reduced emission energy process. Carbondioxide 928 produced by energy generation unit 902 may be separated fromfluids exiting the energy generation unit. Carbon dioxide may beseparated from H₂ at high temperatures by using a hot palladium filmsupported on porous stainless steel or a ceramic substrate, or by usinghigh temperature and pressure swing adsorption. The carbon dioxide maybe sequestered in spent oil shale formation 922, injected into oilproducing fields 924 for enhanced oil recovery by improving mobility andproduction of oil in such fields, sequestered into a deep oil shaleformation 926 containing methane by adsorption and subsequent desorptionof methane, or re-injected 928 into a section of the formation through asynthesis gas production well to enhance production of carbon monoxide.Carbon dioxide leaving the energy generation unit may be sequestered ina dewatered coal bed methane reservoir. The water for synthesis gasgeneration may come from dewatering a coal bed methane reservoir.Additional methane may be produced by alternating carbon dioxide andnitrogen. An example of a method for sequestering carbon dioxide isillustrated in U.S. Pat. No. 5,566,756 to Chaback et al., which isincorporated by reference as if fully set forth herein. Additionalenergy may be utilized by removing heat from the carbon dioxide streamleaving the energy generation unit.

[1308] In an in situ conversion process embodiment, a hot spentformation may be cooled before being used to sequester carbon dioxide. Alarger quantity of carbon dioxide may be adsorbed in a formation if theformation is at ambient or near ambient temperature. In addition,cooling a formation may strengthen the formation. The spent formationmay be cooled by introducing water into the formation. The steamproduced may be removed from the formation through production wells. Thegenerated steam may be used for any desired process. For example, thesteam may be provided to an adjacent portion of a formation to heat theadjacent portion or to generate synthesis gas.

[1309]FIG. 122 illustrates an in situ conversion process embodiment inwhich fluid produced from pyrolysis may be separated into a fuel cellfeed stream and fed into a fuel cell to produce electricity. Theembodiment may include oil shale formation 940 with production well 942that produces pyrolysis fluid. Heater well 944 with electric heater 946may be a heat source that heats, or contributes to heating, theformation. Heater well 944 may also be a production well used to producepyrolysis fluid 948. Pyrolysis fluid from heater well 944 may include H₂and hydrocarbons with carbon numbers less than 5. Larger chainhydrocarbons may be reduced to hydrocarbons with carbon numbers lessthan 5 due to the heat adjacent to heater well 944. Pyrolysis fluid 948produced from heater well 944 may be fed to gas membrane separationsystem 950 to separate H₂ and hydrocarbons with carbon numbers less than5. Fuel cell feed stream 952, which may be substantially composed of H₂,may be fed into fuel cell 954. Air feed stream 956 may be fed into fuelcell 954. Nitrogen stream 958 may be vented from fuel cell 954.Electricity 960 produced from the fuel cell may be routed to a powergrid. Electricity 962 may also be used to power electric heaters 946 inheater wells 944. Carbon dioxide 965 produced in fuel cell 954 may beinjected into formation 940.

[1310] Hydrocarbons having carbon numbers of 4, 3, and 1 typically havefairly high market values. Separation and selling of these hydrocarbonsmay be desirable. Ethane (carbon number 2) may not be sufficientlyvaluable to separate and sell in some markets. Ethane may be sent aspart of a fuel stream to a fuel cell or ethane may be used as ahydrocarbon fluid component of a synthesis gas generating fluid. Ethanemay also be used as a feedstock to produce ethene. In some markets,there may be no market for any hydrocarbons having carbon numbers lessthan 5. In such a situation, all of the hydrocarbon gases producedduring pyrolysis may be sent to fuel cells, used as fuels, and/or beused as hydrocarbon fluid components of a synthesis gas generatingfluid.

[1311] Pyrolysis fluid 964, which may be substantially composed ofhydrocarbons with carbon numbers less than 5, may be injected into a hotformation 940. When the hydrocarbons contact the formation, hydrocarbonsmay crack within the formation to produce methane, H₂, coke, and olefinssuch as ethene and propylene. In one embodiment, the production ofolefins may be increased by heating the temperature of the formation tothe upper end of the pyrolysis temperature range and by injectinghydrocarbon fluid at a relatively high rate. Residence time of thehydrocarbons in the formation may be reduced and dehydrogenatedhydrocarbons may form olefins rather than cracking to form H₂ and coke.Olefin production may also be increased by reducing formation pressure.

[1312] In some in situ conversion process embodiments, a hot formationthat was subjected to pyrolysis and/or synthesis gas generation may beused to produce olefins. Hot formation 940 may be significantly lessefficient at producing olefins than a reactor designed to produceolefins. However, a hot formation may have a several orders of magnitudemore surface area and volume than a reactor designed to produce olefins.The reduction in efficiency of a hot formation may be more than offsetby the increased size of the hot formation. A feed stream for olefinproduction in a hot formation may be produced adjacent to the hotformation from a portion of a formation undergoing pyrolysis. Theavailability of a feed stream may also offset efficiency of a hotformation for producing olefins as compared to generating olefins in areactor designed to produced olefins.

[1313] In some in situ conversion process embodiments, H₂ and/ornon-condensable hydrocarbons may be used as a fuel, or as a fuelcomponent, for surface burners or combustors. The combustors may be heatsources used to heat an oil shale formation. In some heat sourceembodiments, the combustors may be flameless distributed combustors. Insome heat source embodiments, the combustors may be natural distributedcombustors and the fuel may be provided to the natural distributedcombustor to supplement the fuel available from hydrocarbon material inthe formation.

[1314] Heater well 944 may heat a portion of a formation to a synthesisgas generating temperature range. Pyrolysis fluid 964, or a portion ofthe pyrolysis fluid, may be injected into formation 940. In some processembodiments, pyrolysis fluid 964 introduced into formation 940 mayinclude no, or substantially no, hydrocarbons having carbon numbersgreater than about 4. In other process embodiments, pyrolysis fluid 964introduced into formation 940 may include a significant portion ofhydrocarbons having carbon numbers greater than 4. In some processembodiments, pyrolysis fluid 964 introduced into formation 940 mayinclude no, or substantially no, hydrocarbons having carbon numbers lessthan 5. When hydrocarbons in pyrolysis fluid 964 are introduced intoformation 940, the hydrocarbons may crack within the formation toproduce methane, H₂, and coke.

[1315]FIG. 123 depicts an embodiment of a synthesis gas generatingprocess from oil shale formation 976 with flameless distributedcombustor 996. Synthesis gas 980 produced from production well 978 maybe fed into gas separation plant 984. Gas separation plant 984 mayseparate carbon dioxide 986 from other components of synthesis gas 980.First portion 990 of carbon dioxide may be routed to a formation forsequestration. Second portion 992 of carbon dioxide may be injected intothe formation with synthesis gas generating fluid. Portion 993 ofsynthesis gas 988 from separation plant 984 may be introduced intoheater well 994 as a portion of fuel for combustion in flamelessdistributed combustor 996. Flameless distributed combustor 996 mayprovide heat to the formation. Portion 998 of synthesis gas 988 may befed to fuel cell 1000 for the production of electricity. Electricity1002 may be routed to a power grid. Steam 1004 produced in the fuel celland steam 1006 produced from combustion in the distributed burner may beintroduced into the formation as a portion of a synthesis gas generationfluid.

[1316] In an in situ conversion process embodiment, carbon dioxidegenerated with pyrolysis fluids may be sequestered in an oil shaleformation. FIG. 124 illustrates in situ pyrolysis in oil shale formation1020. Heat source 1022 with electric heater 1024 may be placed information 1020. Pyrolysis fluids 1026 may be produced from formation1020 and fed into gas separation unit 1028. Gas separation unit 1028 mayseparate pyrolysis fluid 1026 into carbon dioxide 1030, vapor component1032, and liquid component 1031. Portion 1034 of carbon dioxide 1030 maybe stored in formation 1036. Formation 1036 may be a coal bed withentrained methane. The carbon dioxide may displace some of the methaneand allow for production of methane. The carbon dioxide may besequestered in spent formation 1038, injected into oil producing fields1040 for enhanced oil recovery, or sequestered into coal bed 1042. Insome embodiments, portion 1044 of carbon dioxide 1030 may be re-injectedinto a section of formation 1020 through a synthesis gas production wellto promote production of carbon monoxide.

[1317] Vapor component 1032 and/or carbon dioxide 1030 may pass throughturbine 1033 or turbines to generate electricity. A portion ofelectricity 1035 generated by the vapor component and/or carbon dioxidemay be used to power electric heaters 1024 placed within formation 1020.Initial power and/or make-up power may be provided to electric heatersfrom a power grid.

[1318] As depicted in FIG. 125, heater well 1060 may be located withinoil shale formation 1062. Additional heater wells may also be locatedwithin formation 1062. Heater well 1060 may include electric heater 1064or another type of heat source. Pyrolysis fluid 1066 produced from theformation may be fed to reformer 1068 to produce synthesis gas 1070. Insome process embodiments, reformer 1068 is a steam reformer. Synthesisgas 1070 may be sent to fuel cell 1072. A portion of pyrolysis fluid1060 and/or produced synthesis gas 1070 may be used as fuel to heatsteam reformer 1068. Steam reformer 1068 may include a catalyst materialthat promotes the reforming reaction and a burner to supply heat for theendothermic reforming reaction. A steam source may be connected toreformer 1068 to provide steam for the reforming reaction. The burnermay operate at temperatures well above that required by the reformingreaction and well above the operating temperatures of fuel cells. Assuch, it may be desirable to operate the burner as a separate unitindependent of fuel cell 1072.

[1319] In some process embodiments, reformer 1068 may be a tubereformer. Reformer 1068 may include multiple tubes made of refractorymetal alloys. Each tube may include a packed granular or pelletizedmaterial having a reforming catalyst as a surface coating. A diameter ofthe tubes may vary from between about 9 cm and about 16 cm. A heatedlength of each tube may normally be between about 6 m and about 12 m. Acombustion zone may be provided external to the tubes, and may be formedin the burner. A surface temperature of the tubes may be maintained bythe burner at a temperature of about 900° C. to ensure that thehydrocarbon fluid flowing inside the tube is properly catalyzed withsteam at a temperature between about 500° C. and about 700° C. Atraditional tube reformer may rely upon conduction and convection heattransfer within the tube to distribute heat for reforming.

[1320] Pyrolysis fluids 1066 from formation 1062 may be pre-processedprior to being fed to reformer 1068. Reformer 1068 may transformpyrolysis fluids 1066 into simpler reactants prior to introduction to afuel cell. For example, pyrolysis fluids 1066may be pre-processed in adesulfurization unit. Subsequent to pre-processing, pyrolysis fluids1066 may be provided to a reformer and a shift reactor to produce asuitable fuel stock for a H₂ fueled fuel cell.

[1321] Synthesis gas 1070 produced by reformer 1068 may include a numberof components including carbon dioxide, carbon monoxide, methane, and/orhydrogen. Produced synthesis gas 1070 may be fed to fuel cell 1072.Portion 1074 of electricity produced by fuel cell 1072 may be sent to apower grid. In addition, portion 1076 of electricity may be used topower electric heater 1064. Carbon dioxide 1078 exiting the fuel cellmay be routed to sequestration area 1080. The sequestration area may bea spent portion of formation 1062.

[1322] In a process embodiment, pyrolysis fluid produced from aformation may be fed to the reformer. The reformer may produce carbondioxide stream and a H₂ stream. For example, the reformer may include aflameless distributed combustor for a core, and a membrane. The membranemay allow only H₂ to pass through the membrane resulting in separationof the H₂ and carbon dioxide. The carbon dioxide may be routed to asequestration area.

[1323] Synthesis gas produced from a formation may be converted toheavier condensable hydrocarbons. For example, a Fischer-Tropschhydrocarbon synthesis process may be used for conversion of synthesisgas. A Fischer-Tropsch process may include converting synthesis gas tohydrocarbons. The process may use elevated temperatures, normal orelevated pressures, and a catalyst, such as magnetic iron oxide or acobalt catalyst. Products produced from a Fischer-Tropsch process mayinclude hydrocarbons having a broad molecular weight distribution andmay include branched and/or unbranched paraffins. Products from aFischer-Tropsch process may also include considerable quantities ofolefins and oxygen containing organic compounds. An example of aFischer-Tropsch reaction may be illustrated by Reaction 49:

(n+2)CO+(2n+5)H₂

CH₃(—CH₂—)_(n)CH₃+(n+2)H₂O  (49)

[1324] A hydrogen to carbon monoxide ratio for synthesis gas used as afeed gas for a Fischer-Tropsch reaction may be about 2:1. In certainembodiments, the ratio may range from approximately 1.8:1 to 2.2:1.Higher or lower ratios may be accommodated by certain Fischer-Tropschsystems.

[1325]FIG. 126 illustrates a flow chart of a Fischer-Tropsch processthat uses synthesis gas produced from an oil shale formation as a feedstream. Hot formation 1090 may be used to produce synthesis gas having aH₂ to CO ratio of approximately 2:1. The proper ratio may be produced byoperating synthesis production wells at approximately 700° C., or byblending synthesis gas produced from different sections of formation toobtain a synthesis gas having approximately a 2:1 H₂ to CO ratio.Synthesis gas generating fluid 1092 may be fed into hot formation 1090to generate synthesis gas. H₂ and CO may be separated from the synthesisgas produced from the hot formation 1090 to form feed stream 1094. Feedstream 1094 may be sent to Fischer-Tropsch plant 1096. Feed stream 1094may supplement or replace synthesis gas 1098 produced from catalyticmethane reformer 1100.

[1326] Fischer-Tropsch plant 1096 may produce wax feed stream 1102. TheFischer-Tropsch synthesis process that produces wax feed stream 1102 isan exothermic process. Steam 1104 may be generated during theFischer-Tropsch process. Steam 1104 may be used as a portion ofsynthesis gas generating fluid 1092.

[1327] Wax feed stream 1102 produced from Fischer-Tropsch plant 1096 maybe sent to hydrocracker 1106. Hydrocracker 1106 may produce productstream 1108. The product stream may include diesel, jet fuel, and/ornaphtha products. Examples of methods for conversion of synthesis gas tohydrocarbons in a Fischer-Tropsch process are illustrated in U.S. Pat.Nos. 4,096,163 to Chang et al., 6,085,512 to Agee et al., and 6,172,124to Wolflick et al., which are incorporated by reference as if fully setforth herein.

[1328]FIG. 127 depicts an embodiment of in situ synthesis gas productionintegrated with a Shell Middle Distillates Synthesis (SMDS)Fischer-Tropsch and wax cracking process. An example of a SMDS processis illustrated in U.S. Pat. No. 4,594,468 to Minderhoud, and isincorporated by reference as if fully set forth herein. A middledistillates hydrocarbon mixture may be produced from produced synthesisgas using the SMDS process as illustrated in FIG. 127. Synthesis gas1120, having a H₂ to carbon monoxide ratio of about 2:1, may exitproduction well 1128. The synthesis gas may be fed into SMDS plant 1122.In certain embodiments, the ratio may range from approximately 1.8:1 to2.2:1. Products of the SMDS plant include organic liquid product 1124and steam 1126. Steam 1126 may be supplied to injection wells 1127.Steam may be used as a feed for synthesis gas production. Hydrocarbonvapors may in some circumstances be added to the steam.

[1329]FIG. 128 depicts an embodiment of in situ synthesis gas productionintegrated with a catalytic methanation process. Synthesis gas 1140exiting production well 1142 may be supplied to catalytic methanationplant 1144. Synthesis gas supplied to catalytic methanation plant 1144may have a H₂ to carbon monoxide ratio of about 3:1. Methane 1146 may beproduced by catalytic methanation plant 1144. Steam 1148 produced byplant 1144 may be supplied to injection well 1141 for production ofsynthesis gas. Examples of a catalytic methanation process areillustrated in U.S. Pat. Nos. 3,922,148 to Child; 4,130,575 to Jorn etal.; and 4,133,825 to Stroud et al., which are incorporated by referenceas if fully set forth herein.

[1330] Synthesis gas produced from a formation may be used as a feed fora process for producing methanol. Examples of processes for productionof methanol are described in U.S. Pat. Nos. 4,407,973 to van Dijk etal., 4,927,857 to McShea, III et al., and 4,994,093 to Wetzel et al.,each of which is incorporated by reference as if fully set forth herein.The produced synthesis gas may also be used as a feed gas for a processthat converts synthesis gas to engine fuel (e.g., gasoline or diesel).Examples of process for producing engine fuels are described in U.S.Pat. Nos. 4,076,761 to Chang et al., 4,138,442 to Chang et al., and4,605,680 to Beuther et al., each of which is incorporated by referenceas if fully set forth herein.

[1331] In a process embodiment, produced synthesis gas may be used as afeed gas for production of ammonia and urea. FIGS. 129 and 130 depictembodiments of making ammonia and urea from synthesis gas. Ammonia maybe synthesized by the Haber-Bosch process, which involves synthesisdirectly from N₂ and H₂ according to Reaction 50:

N₂+3H₂

2NH₃.  (50)

[1332] The N₂ and H₂ may be combined, compressed to high pressure,(e.g., from about 80 bars to about 220 bars), and then heated to arelatively high temperature. The reaction mixture may be passed over acatalyst composed substantially of iron to produce ammonia. Duringammonia synthesis, the reactants (i.e., N₂ and H₂) and the product(i.e., ammonia) may be in equilibrium. The total amount of ammoniaproduced may be increased by shifting the equilibrium towards productformation. Equilibrium may be shifted to product formation by removingammonia from the reaction mixture as ammonia is produced.

[1333] Removal of the ammonia may be accomplished by cooling the gasmixture to a temperature between about −5° C. to about 25° C. In thistemperature range, a two-phase mixture may be formed with ammonia in theliquid phase and N₂ and H₂ in the gas phase. The ammonia may beseparated from other components of the mixture. The nitrogen andhydrogen may be subsequently reheated to the operating temperature forammonia conversion and passed through the reactor again.

[1334] Urea may be prepared by introducing ammonia and carbon dioxideinto a reactor at a suitable pressure, (e.g., from about 125 barsabsolute to about 350 bars absolute), and at a suitable temperature,(e.g., from about 160° C. to about 250° C.). Ammonium carbamate may beformed according to Reaction 51:

2NH₃+CO₂→NH₂(CO₂)NH₄.  (51)

[1335] Urea may be subsequently formed by dehydrating the ammoniumcarbamate according to equilibrium Reaction 52:

NH₂(CO₂)NH₄

NH₂(CO)NH₂+H₂O.  (52)

[1336] The degree to which the ammonia conversion takes place may dependon the temperature and the amount of excess ammonia. The solutionobtained as the reaction product may include urea, water, ammoniumcarbamate, and unbound ammonia. The ammonium carbamate and the ammoniamay need to be removed from the solution and returned to the reactor.The reactor may include separate zones for the formation of ammoniumcarbamate and urea. However, these zones may also be combined into onepiece of equipment.

[1337] In a process embodiment, a high pressure urea plant may operatesuch that the decomposition of ammonium carbamate that has not beenconverted into urea and the expulsion of the excess ammonia areconducted at a pressure between 15 bars absolute and 100 bars absolute.This pressure may be considerably lower than the pressure in the ureasynthesis reactor. The synthesis reactor may be operated at atemperature of about 180° C. to about 210° C. and at a pressure of about180 bars absolute to about 300 bars absolute. Ammonia and carbon dioxidemay be directly fed to the urea reactor. The NH₃/CO₂ molar ratio (N/Cmolar ratio) in the urea synthesis may generally be between about 3 andabout 5. The unconverted reactants may be recycled to the urea synthesisreactor following expansion, dissociation, and/or condensation.

[1338] In a process embodiment, an ammonia feed stream having a selectedratio of H₂ to N₂ may be generated from a formation using enriched air.A synthesis gas generating fluid and an enriched air stream may beprovided to the formation. The composition of the enriched air may beselected to generate synthesis gas having the selected ratio of H₂ toN₂. In one embodiment, the temperature of the formation may becontrolled to generate synthesis gas having the selected ratio.

[1339] In a process embodiment, the H₂ to N₂ ratio of the feed streamprovided to the ammonia synthesis process may be approximately 3:1. Inother embodiments, the ratio may range from approximately 2.8:1 to3.2:1. An ammonia synthesis feed stream having a selected H₂ to N₂ ratiomay be obtained by blending feed streams produced from differentportions of the formation.

[1340] In a process embodiment, ammonia from the ammonia synthesisprocess may be provided to a urea synthesis process to generate urea.Ammonia produced during pyrolysis may be added to the ammonia generatedfrom the ammonia synthesis process. In another process embodiment,ammonia produced during hydrotreating may be added to the ammoniagenerated from the ammonia synthesis process. Some of the carbonmonoxide in the synthesis gas may be converted to carbon dioxide in ashift process. The carbon dioxide from the shift process may be fed tothe urea synthesis process. Carbon dioxide generated from treatment ofthe formation may also be fed, in some embodiments, to the ureasynthesis process.

[1341]FIG. 129 illustrates an embodiment of a method for production ofammonia and urea from synthesis gas using membrane-enriched air.Enriched air 1170 and steam, or water, 1172 may be fed into hot carboncontaining formation 1174 to produce synthesis gas 1176 in a wetoxidation mode.

[1342] In some synthesis gas production embodiments, enriched air 1170is blended from air and oxygen streams such that the nitrogen tohydrogen ratio in the produced synthesis gas is about 1:3. The synthesisgas may be at a correct ratio of nitrogen and hydrogen to form ammonia.For example, it has been calculated that for a formation temperature of700° C., a pressure of 3 bars absolute, and with 13,231 tons/day of charthat will be converted into synthesis gas, one could inject 14.7kilotons/day of air, 6.2 kilotons/day of oxygen, and 21.2 kilotons/dayof steam. This would result in production of 2 billion cubic feet/day ofsynthesis gas including 5689 tons/day of steam, 16,778 tons/day ofcarbon monoxide, 1406 tons/day of hydrogen, 18,689 tons/day of carbondioxide, 1258 tons/day of methane, and 11,398 tons/day of nitrogen.After a shift reaction (to shift the carbon monoxide to carbon dioxideand to produce additional hydrogen), the carbon dioxide may be removed,the product stream may be methanated (to remove residual carbonmonoxide), and then one can theoretically produce 13,840 tons/day ofammonia and 1258 tons/day of methane. This calculation includes theproducts produced from Reactions (46) and (47) above.

[1343] Enriched air may be produced from a membrane separation unit.Membrane separation of air may be primarily a physical process. Basedupon specific characteristics of each molecule, such as size andpermeation rate, the molecules in air may be separated to formsubstantially pure forms of nitrogen, oxygen, or combinations thereof.

[1344] In a membrane system embodiment, the membrane system may includea hollow tube filled with a plurality of very thin membrane fibers. Eachmembrane fiber may be another hollow tube in which air flows. The wallsof the membrane fiber may be porous such that oxygen permeates throughthe wall at a faster rate than nitrogen. A nitrogen rich stream may beallowed to flow out the other end of the fiber. Air outside the fiberand in the hollow tube may be oxygen enriched. Such air may be separatedfor subsequent uses, such as production of synthesis gas from aformation.

[1345] In some membrane system embodiments, the purity of nitrogengenerated may be controlled by variation of the flow rate and/orpressure of air through the membrane. Increasing air pressure mayincrease permeation of oxygen molecules through a fiber wall. Decreasingflow rate may increase the residence time of oxygen in the membrane and,thus, may increase permeation through the fiber wall. Air pressure andflow rate may be adjusted to allow a system operator to vary the amountand purity of the nitrogen generated in a relatively short amount oftime.

[1346] The amount of N₂ in the enriched air may be adjusted to provide aN:H ratio of about 3:1 for ammonia production. Synthesis gas may begenerated at a temperature that favors the production of carbon dioxideover carbon monoxide. The temperature during synthesis gas may bemaintained between about 400° C. and about 550° C., or between about400° C. and about 450° C. Synthesis gas produced at such lowtemperatures may include N₂, H₂, and carbon dioxide with little carbonmonoxide.

[1347] As illustrated in FIG. 129, a feed stream for ammonia productionmay be prepared by first feeding synthesis gas stream 1176 into ammoniafeed stream gas processing unit 1178. In ammonia feed stream gasprocessing unit 1178, the feed stream may undergo a shift reaction (toshift the carbon monoxide to carbon dioxide and to produce additionalhydrogen). Carbon dioxide may be removed from the feed stream, and thefeed stream can be methanated (to remove residual carbon monoxide). Incertain embodiments, carbon dioxide may be separated from the feedstream (or any gas stream) by absorption in an amine unit. Membranes orother carbon dioxide separation techniques/equipment may also be used toseparate carbon dioxide from a feed stream.

[1348] Ammonia feed stream 1180 may be fed to ammonia productionfacility 1182 to produce ammonia 1184. Carbon dioxide 1186 exiting gasseparation unit 1178 (and/or carbon dioxide from other sources) may befed, with ammonia 1184, into urea production facility 1188 to produceurea 1190.

[1349] Ammonia and urea may be produced using a carbon containingformation and using an O₂ rich stream and a N₂ rich stream. The O₂ richstream and synthesis gas generating fluid may be provided to aformation. The formation may be heated, or partially heated, byoxidation of carbon in the formation with the O₂ rich stream. H₂ in thesynthesis gas and N₂ from the N₂ rich stream may be provided to anammonia synthesis process to generate ammonia.

[1350]FIG. 130 illustrates a flow chart of an embodiment for productionof ammonia and urea from synthesis gas using cryogenically separatedair. Air 2000 may be fed into cryogenic air separation unit 2002.Cryogenic separation involves a distillation process that may occur attemperatures between about −168° C. and −172° C. In other embodiments,the distillation process may occur at temperatures between about −165°C. and −175° C. Air may liquefy in these temperature ranges. Thedistillation process may be operated at a pressure between about 8 barsabsolute and about 10 bars absolute. High pressures may be achieved bycompressing air and exchanging heat with cold air exiting the column.Nitrogen is more volatile than oxygen and may come off as a distillateproduct.

[1351] N₂ 2004 exiting separator 2002 may be utilized in heat exchanger2006 to condense higher molecular weight hydrocarbons from pyrolysisstream 2008 and to remove lower molecular weight hydrocarbons from thegas phase into a liquid oil phase. Upgraded gas stream 2010 containing ahigher composition of lower molecular weight hydrocarbons than stream2008 and liquid stream 2012, which includes condensed hydrocarbons, mayexit heat exchanger 2006. N₂ 2004 may also exit heat exchanger 2006.

[1352] Oxygen 2014 from cryogenic separation unit 2002 and steam 2016,or water, may be fed into hot carbon containing formation 2018 toproduce synthesis gas 2020 in a continuous process. Synthesis gas may begenerated at a temperature that favors the formation of carbon dioxideover carbon monoxide. Synthesis gas 2020 may include H₂ and carbondioxide. Carbon dioxide may be removed from synthesis gas 2020 toprepare a feed stream for ammonia production using amine gas separationunit 2022. H₂ stream 2024 from gas separation unit 2022 and N₂ stream2004 from the heat exchanger may be fed into ammonia production facility2028 to produce ammonia 2030. Carbon dioxide 2032 exiting gas separationunit 2022 and ammonia 2030 may be fed into urea production facility 2034to produce urea 2036.

[1353]FIG. 131 illustrates an embodiment of a method for preparing anitrogen stream for an ammonia and urea process. Air 2060 may beinjected into hot carbon containing formation 2062 to produce carbondioxide by oxidation of carbon in the formation. In an embodiment, aheater may heat at least a portion of the carbon containing formation toa temperature sufficient to support oxidation of the carbon. Stream 2064exiting the hot formation may include carbon dioxide and nitrogen. Insome embodiments, a flue gas stream may be added to stream 2064, orstream 2064 may be a flue gas stream instead of a stream from a portionof a formation.

[1354] Nitrogen may be separated from carbon dioxide in stream 2064 bypassing the stream through cold spent carbon containing formation 2066.Carbon dioxide may preferentially adsorb versus nitrogen in cold spentformation 2066. Nitrogen 2068 exiting cold spent portion 2066 may besupplied to ammonia production facility 2070 with H₂ stream 2072 toproduce ammonia 2074. In some process embodiments, H₂ stream 2072 may beobtained from a product stream produced during synthesis gas generationof a portion of the formation.

[1355] In an embodiment, an in situ process for treating a formation mayinclude providing heat to a portion of a formation from a plurality ofheat sources. A plurality of heat sources may be arranged within aformation in a pattern. FIG. 132 illustrates an embodiment of pattern2404 of heat sources 2400 and production well 2402 that may treat aformation. Heat sources 2400 may be arranged in a “5 spot” pattern withproduction well 2402. In the “5 spot” pattern, four heat sources 2400are arranged substantially around production well 2402, as depicted inFIG. 132. Although heat sources 2400 are depicted as being equidistantfrom each other in FIG. 132, the heat sources may be placed aroundproduction well 2402 and not be equidistant from the production welland/or each other. Depending on the heat generated by each heat source2400, a spacing between heat sources 2400 and production well 2402 maybe determined by a desired product or a desired production rate. Aspacing between heat sources 2400 and production well 2402 may be, forexample, about 15 m. A heat source 2400 may be converted into productionwell 2402. A production well 2402 may be converted into a heat source2400.

[1356]FIG. 133 illustrates an alternate embodiment of pattern 2406 ofheat sources 2400 arranged in a “7 spot” pattern with production well2402. In the “7 spot” pattern, six heat sources 2400 are arrangedsubstantially around production well 2402, as depicted in FIG. 133.Although heat sources 2400 are depicted as being equidistant from eachother in FIG. 133, the heat sources may be placed around production well2402 and not be equidistant from the production well and/or each other.Heat sources 2400 may also be used to produce fluids from the formation.In addition, production well 2402 may be heated.

[1357] In certain embodiments, a pattern of heat sources 2400 andproduction wells 2402 may vary depending on, for example, the type offormation to be treated. A location of production well 2402 within apattern of heat sources 2400 may be determined by, for example, adesired heating rate of the formation, a heating rate of the heatsources, a type of heat source, a type of formation, a composition ofthe formation, a viscosity of fluid in the formation, and/or a desiredproduction rate.

[1358] In an embodiment, production of hydrocarbons from a formation isinhibited until at least some hydrocarbons within the formation havebeen pyrolyzed. A mixture may be produced from the formation at a timewhen the mixture includes a selected quality in the mixture (e.g., APIgravity, hydrogen concentration, aromatic content, etc.). In someembodiments, the selected quality includes an API gravity of at leastabout 20°, 30°, or 40°. Inhibiting production until at least somehydrocarbons are pyrolyzed may increase conversion of hydrocarbons tolighter hydrocarbons.

[1359] In one embodiment, the time for beginning production may bedetermined by sampling a test stream produced from the formation. Thetest stream may be an amount of fluid produced through a production wellor a test well. The test stream may be a portion of fluid removed fromthe formation to control pressure within the formation. The test streammay be tested to determine if the test stream has a selected quality.For example, the selected quality may be a selected minimum API gravityor a selected maximum weight percentage of hydrocarbons. When the teststream has the selected quality, production of the mixture may bestarted through production wells and/or heat sources in the formation.

[1360] In an embodiment, the time for beginning production is determinedfrom laboratory experimental treatment of samples obtained from theformation. For example, a laboratory treatment may include a pyrolysisexperiment used to determine a process time that produces a selectedminimum API gravity from the sample.

[1361] In one embodiment, measuring a pressure (e.g., a downholepressure in a production well) is used to determine the time forbeginning production from a formation. For example, production may bestarted when a minimum selected downhole pressure is reached in aproduction well in a selected section of the formation.

[1362] In an embodiment, the time for beginning production is determinedfrom a simulation for treating the formation. The simulation may be acomputer simulation that simulates formation conditions (e.g., pressure,temperature, production rates, etc.) to determine qualities in fluidsproduced from the formation.

[1363] When production of hydrocarbons from the formation is inhibited,the pressure in the formation tends to increase with temperature in theformation because of thermal expansion and/or phase change ofhydrocarbons and other fluids (e.g., water) in the formation. Pressurewithin the formation may have to be maintained below a selected pressureto inhibit unwanted production, fracturing of the overburden orunderburden, and/or coking of hydrocarbons in the formation. Theselected pressure may be a lithostatic or hydrostatic pressure of theformation. For example, the selected pressure may be about 150 barsabsolute or, in some embodiments, the selected pressure may be about 35bars absolute. The pressure in the formation may be controlled bycontrolling production rate from production wells in the formation. Inother embodiments, the pressure in the formation is controlled byreleasing pressure through one or more pressure relief wells in theformation. Pressure relief wells may be heat sources or separate wellsinserted into the formation. Formation fluid removed from the formationthrough the relief wells may be sent to a surface facility. Producing atleast some hydrocarbons from the formation may inhibit the pressure inthe formation from rising above the selected pressure.

[1364] In certain embodiments, some formation fluids may be backproduced through a heat source wellbore. For example, some formationfluids may be back produced through a heat source wellbore during earlytimes of heating of an oil shale formation. In an embodiment, someformation fluids may be produced through a portion of a heat sourcewellbore. Injection of heat may be adjusted along the length of thewellbore so that fluids produced through the wellbore are notoverheated. Fluids may be produced through portions of the heat sourcewellbore that are at lower temperatures than other portions of thewellbore.

[1365] Producing at least some formation fluids through a heat sourcewellbore may reduce or eliminate the need for additional productionwells in a formation. In addition, pressures within the formation may bereduced by producing fluids through a heat source wellbore (especiallywithin the region surrounding the heat source wellbore). Reducingpressures in the formation may alter the ratio of produced liquids toproduced vapors. In certain embodiments, producing fluids through theheat source wellbore may lead to earlier production of fluids from theformation. Portions of the formation closest to the heat source wellborewill increase to mobilization and/or pyrolysis temperatures earlier thanportions of the formation near production wells. Thus, fluids may beproduced at earlier times from portions near the heat source wellbore.

[1366]FIG. 134 depicts an embodiment of a heater well for selectivelyheating a formation. Heat source 9628 may be placed in opening 514 inhydrocarbon layer 516. In certain embodiments, opening 514 may be asubstantially horizontal opening within hydrocarbon layer 516.Perforated casing 9636 may be placed in opening 514. Perforated casing9636 may provide support from hydrocarbon and/or other material inhydrocarbon layer 516 collapsing opening 514. Perforations in perforatedcasing 9636 may allow for fluid flow from hydrocarbon layer 516 intoopening 514. Heat source 9628 may include hot portion 9622. Hot portion9622 may be a portion of heat source 9628 that operates at higher heatoutputs of a heat source. For example, hot portion 9622 may outputbetween about 650 watts per meter and about 1650 watts per meter. Hotportion 9622 may extend from a “heel” of the heat source to the end ofthe heat source (i.e., the “toe” of the heat source). The heel of a heatsource is the portion of the heat source closest to the point at whichthe heat source enters a hydrocarbon layer. The toe of a heat source isthe end of the heat source furthest from the entry of the heat sourceinto a hydrocarbon layer.

[1367] In an embodiment, heat source 9628 may include warm portion 9624.Warm portion 9624 may be a portion of heat source 9628 that operates atlower heat outputs than hot portion 9622. For example, warm portion 9624may output between about 150 watts per meter and about 650 watts permeter. Warm portion 9624 may be located closer to the heel of heatsource 9628. In certain embodiments, warm portion 9624 may be atransition portion (i.e., a transition conductor) between hot portion9622 and overburden portion 9626. Overburden portion 9626 may be locatedwithin overburden 540. Overburden portion 9626 may provide a lower heatoutput than warm portion 9624. For example, overburden portion mayoutput between about 30 watts per meter and about 90 watts per meter. Insome embodiments, overburden portion 9626 may provide as close to noheat (0 watts per meter) as possible to overburden 540. Some heat,however, may be used to maintain fluids produced through opening 514 ina vapor phase within overburden 540.

[1368] In certain embodiments, hot portion 9622 of heat source 9628 mayheat hydrocarbons to high enough temperatures to result in coke 9630forming in hydrocarbon layer 516. Coke 9630 may occur in an areasurrounding opening 514. Warm portion 9624 may be operated at lower heatoutputs such that coke does not form at or near the warm portion of heatsource 9628. Coke 9630 may extend radially from opening 514 as heat fromheat source 9628 transfers outward from the opening. At a certaindistance, however, coke 9630 no longer forms because temperatures inhydrocarbon layer 516 at the certain distance will not reach cokingtemperatures. The distance at which no coke forms may be a function ofheat output (watts per meter from heat source 9628), type of formation,hydrocarbon content in the formation, and/or other conditions within theformation.

[1369] The formation of coke 9630 may inhibit fluid flow into opening514 through the coking. Fluids in the formation may, however, beproduced through opening 514 at the heel of heat source 9628 (i.e., atwarm portion 9624 of the heat source) where there is no coke formation.The lower temperatures at the heel of heat source 9628 may reduce thepossibility of increased cracking of formation fluids produced throughthe heel. Fluids may flow in a horizontal direction through theformation more easily than in a vertical direction. Thus, fluids mayflow along the length of heat source 9628 in a substantially horizontaldirection. Producing formation fluids through opening 514 may bepossible at earlier times than producing fluids through production wellsin hydrocarbon layer 516. The earlier production times through opening514 may be possible because temperatures near the opening increasefaster than temperatures further away due to conduction of heat fromheat source 9628 through hydrocarbon layer 516. Early production offormation fluids may be used to maintain lower pressures in hydrocarbonlayer 516 during start-up heating of the formation (i.e., beforeproduction begins at production wells in the formation). Lower pressuresin the formation may increase liquid production from the formation. Inaddition, producing formation fluids through opening 514 may reduce thenumber of production wells needed in the formation.

[1370] Alternately, in certain embodiments portions of a heater may bemoved or removed, thereby shortening the heated section. For example, ina horizontal well the heater may initially extend to the “toe.” Asproducts are produced from the formation, the heater may be moved sothat it is placed at location further from the “toe.” Heat may beapplied to a different portion of the formation.

[1371] Producing formation fluids in the upper portion of the formationmay allow for production of hydrocarbons substantially in a vapor phase.Lighter hydrocarbons may be produced from production wells placed in theupper portion of the oil shale formation. Hydrocarbons produced from anupper portion of the formation may be upgraded as compared tohydrocarbons produced from a lower portion of the formation. Producingthrough wells in the upper portion may also inhibit coking of producedfluids at the production wellbore. Producing through wells placed in alower portion of the formation may produce a heavier hydrocarbon fluidthan is produced in the upper portion of the formation. In someembodiments, the upper portion of the formation may include an upperhalf of the formation. However, a size of the upper portion may varydepending on several factors (e.g., a thickness of the formation,vertical permeability of the formation, a desired quality of producedfluid, or a desired production rate).

[1372] In some embodiments, a quality of a mixture produced from aformation is controlled by varying a location for producing the mixturewithin the formation. The quality of the mixture produced may be ratedon variety of factors (e.g., API gravity of the mixture, carbon numberdistribution, a weight ratio of components in the mixture, and/or apartial pressure of hydrogen in the mixture). Other qualities of themixture may include, but are not limited to, a ratio of heavyhydrocarbons to light hydrocarbons in the mixture and/or a ratio ofaromatics to paraffins in the mixture. In one embodiment, the locationfor producing the mixture is varied by varying a location of aproduction well within the formation. For example, the quality of themixture can be varied by varying a distance between a production welland a heat source. Locating the production well closer to the heatsource may increase cracking at or near the production well, thus,increasing, for example, an API gravity of the mixture produced. In someembodiments, a number of production wells in a portion of the formationor a production rate from a portion of the formation may be used tocontrol the quality of a mixture produced

[1373] In some embodiments, varying a location for production includesvarying a portion of the formation from which the mixture is produced.For example, a mixture may be produced from an upper portion of theformation, a middle portion of the formation, and/or a lower portion ofthe formation at various times during production from a formation.Varying the portion of the formation from which the mixture is producedmay include varying a depth of a production well within the formationand/or varying a depth for producing the mixture within a productionwell. In certain embodiments, the quality of the produced mixture isincreased by producing in an upper portion of the formation rather thana middle or lower portion of the formation. Producing in the upperportion tends to increase the amount of vapor phase and/or lighthydrocarbon production from the formation. Producing in lower portionsof the formation may decrease a quality of the produced mixture.

[1374] In certain embodiments, an upper portion of the formationincludes about one-third of the formation closest to an overburden ofthe formation. The upper portion of the formation, however, may includeup to about 35%, 40%, or 45% of the formation closest to the overburden.A lower portion of the formation may include a percentage of theformation closest to an underburden, or base rock, of the formation thatis substantially equivalent to the percentage of the formation that isincluded in the upper portion. A middle portion of the formation mayinclude the remainder of the formation between the upper portion and thelower portion. For example, the upper portion may include aboutone-third of the formation closest to the overburden while the lowerportion includes about one-third of the formation closest to theunderburden and the middle portion includes the remaining third of theformation between the upper portion and the lower portion. FIG. 135(described below) depicts embodiments of upper portion 8620, middleportion 8622, and lower portion 8624 in hydrocarbon layer 6704 alongwith production well 6710.

[1375] In some embodiments, the lower portion includes a differentpercentage of the formation than the upper portion. For example, theupper portion may include about 30% of the formation closest to theoverburden while the lower portion includes about 40% of the formationclosest to the underburden and the middle portion includes the remaining30% of the formation. Percentages of the formation included in theupper, middle, and lower portions of the formation may vary dependingon, for example, placement of heat sources in the formation, spacing ofheat sources in the formation, a structure of the formation (e.g.,impermeable layers within the formation), etc. In some embodiments, aformation may include only an upper portion and a lower portion. Inaddition, the percentages of the formation included in the upper,middle, and lower portions of the formation may vary due to variation ofpermeability within the formation. In some formations, permeability mayvary vertically within the formation. For example, the permeability inthe formation may be lower in an upper portion of the formation than alower portion of the formation.

[1376] In an embodiment, selecting the location for producing a mixturefrom a formation includes selecting the location based on a pricecharacteristic for the produced mixture. The price characteristic may bea price characteristic of hydrocarbons produced from the formation. Theprice characteristic may be determined by multiplying a production rateof the produce mixture at a selected API gravity by a price obtainablefor selling the produced mixture with the selected API gravity. In someembodiments, the price characteristic may be determined as a function ofthe API gravity of the produced mixture, the total mass recovery fromthe formation, a price obtainable for selling the produced mixture,and/or other factors affecting production of the mixture from theformation. Other characteristics, however, may also be included in theprice characteristic. For example, other characteristics may include,but are not limited to, a selling price of hydrocarbon components in theproduced mixture, a selling price of sulfur produced, a selling price ofmetals produced, a ratio of paraffins to aromatics produced, and/or aweight percentage of heavy hydrocarbons in the mixture.

[1377] In some instances, the price characteristic may change duringproduction of the mixture from the formation. The price characteristicmay change, for example, based on a change in the selling price of theproduced mixture or of a hydrocarbon component in the mixture. In such acase, a parameter for producing the mixture may be adjusted based on thechange in the price characteristic. In an embodiment, the parameter forproducing the mixture is a location for producing the mixture within theformation.

[1378] In some embodiments, the parameter may include operatingconditions within the formation that are controlled based on the pricecharacteristic. Operating conditions may include parameters such as, butnot limited to, pressure, temperature, heating rate, and heat outputfrom one or more heat sources. Operating conditions within the formationmay be adjusted based on a change in the price characteristic duringproduction of the mixture from the formation.

[1379] In certain embodiments, the price characteristic may be based ona relationship between cumulative oil (hydrocarbon) recovery and APIgravity. Generally, increasing the API gravity produced from a formationby an in situ conversion process tends to decrease the cumulativehydrocarbon recovery from the formation (i.e., total mass recovery). Inan embodiment, the relationship between API gravity of the producedhydrocarbons and total mass recovery is a linear relationship. Thelinear relationship may be based on, for example, experimental data(e.g., pyrolysis data) and/or simulation data (e.g., STARS simulationdata).

[1380] In an embodiment, a location from which the mixture is producedis varied by varying a production depth within a production well. Themixture may be produced from different portions of, or locations in, theformation to control the quality of the produced mixture. A productiondepth within a production well may be adjusted to vary a portion of theformation from which the mixture is produced. In some embodiments, theproduction depth is determined before producing the mixture from theformation. In other embodiments, the production depth may be adjustedduring production of the mixture to control the quality of the producedmixture. In certain embodiments, production depth within a productionwell includes varying a production location along a length of theproduction wellbore. For example, the production location may be at anydepth along the length of a substantially vertical production wellborelocated within the formation or at any position along the length of asubstantially horizontal production wellbore. Changing the depth of theproduction location within the formation may change a quality of themixture produced from the formation.

[1381] In some embodiments, varying the production location within aproduction well includes varying a packing height within the productionwell. For example, the packing height may be changed within theproduction well to change the portion of the production well thatproduces fluids from the formation. Packing within the production welltends to inhibit production of fluids at locations where the packing islocated. In other embodiments, varying the production location within aproduction well includes varying a location of perforations on theproduction wellbore used to produce the mixture. Perforations on theproduction wellbore may be used to allow fluids to enter into theproduction well. Varying the location of these perforations may change alocation or locations at which fluids can enter the production well.

[1382]FIG. 135 depicts a cross-sectional representation of an embodimentof production well 6710 placed in hydrocarbon layer 6704. Hydrocarbonlayer 6704 may include upper portion 8620, middle portion 8622, andlower portion 8624. Production well 6710 may be placed within all threeportions 8620, 8622, 8624 within hydrocarbon layer 6704 or within onlyone or more portions of the formation. As shown in FIG. 135, productionwell 6710 may be placed substantially vertically within hydrocarbonlayer 6704. Production well 6710, however, may be placed at other angles(e.g., horizontal or at other angles between horizontal and vertical)within hydrocarbon layer 6704 depending on, for example, a desiredproduct mixture, a depth of overburden 540, a desired production rate,etc.

[1383] Packing 8610 may be placed within production well 6710. Packing8610 tends to inhibit production of fluids at locations of the packingwithin the wellbore (i.e., fluids are inhibited from flowing intoproduction well 6710 at the packing). A height of packing 8610 withinproduction well 6710 may be adjusted to vary the depth in the productionwell from which fluids are produced. For example, increasing the packingheight decreases the maximum depth in the formation at which fluids maybe produced through production well 6710. Decreasing the packing heightwill increase the depth for production. In some embodiments, layers ofpacking 8610 may be placed at different heights within the wellbore toinhibit production of fluids at the different heights. Conduit 8611 maybe placed through packing 8610 to produce fluids entering productionwell 6710 beneath the packing layers.

[1384] One or more perforations 8612 may be placed along a length ofproduction well 6710. Perforations 8612 may be used to allow fluids toenter into production well 6710. In certain embodiments, perforations8612 are placed along an entire length of production well 6710 to allowfluids to enter into the production well at any location along thelength of the production well. In other embodiments, locations ofperforations 8612 may be varied to adjust sections along the length ofproduction well 6710 that are used for producing fluids from theformation. In some embodiments, one or more perforations 8612 may beclosed (shut-in) to inhibit production of fluids through the one or moreperforations. For example, a sliding member may be placed overperforations 8612 that are to be closed to inhibit production. Certainperforations 8612 along production well 6710 may be closed or opened atselected times to allow production of fluids at different locationsalong the production well at the selected times.

[1385] In one embodiment, a first mixture is produced from upper portion8620. A second mixture may be produced from middle portion 8622. A thirdmixture may be produced from lower portion 8624. The first, second, andthird mixtures may be produced at different times during treatment ofthe formation. For example, the first mixture may be produced before thesecond mixture or the third mixture and the second mixture may beproduced before the third mixture. In certain embodiments, the firstmixture is produced such that the first mixture has an API gravitygreater than about 20°. The second mixture or the third mixture may alsobe produced such that each mixture has an API gravity greater than about20°. A time at which each mixture is produced with an API gravitygreater than about 20° may be different for each of the mixtures. Forexample, the first mixture may be produced at an earlier time thaneither the second or the third mixture. The first mixture may beproduced earlier because the first mixture is produced from upperportion 8620. Fluids in upper portion 8620 tend to have a higher APIgravity at earlier times than fluids in middle portion 8622 or lowerportion 8624 due to gravity drainage of heavier fluids in the formationand/or higher vapor phase production in higher portions of theformation.

[1386] In some embodiments, hydrocarbon fluids produced from an oilshale formation may have a relatively low acid number. “Acid number” isdefined as the number of milligrams of KOH (potassium hydroxide)required to neutralize one gram of oil (i.e., bring the oil to a pH of7). Higher acid hydrocarbon fluids (e.g., greater than about 1 mg/gramKOH) are typically more expensive to refine and generally considered tohave a less desirable quality. Generally, fluids with acid numbers lessthan about 1 are desired. Heavy hydrocarbon fluids produced from oilshale formations using standard production techniques such as coldproduction or steam flooding may have a high acid number due to thepresence of naphthenic, humic, or other acids in the producedhydrocarbons. Hydrocarbon fluids produced from a formation using an insitu recovery process (e.g., pyrolyzed fluids) may have a lower acidnumber due to acid-reducing reactions during heating of the formation.For example, decarboxylation may reduce the amount of carboxylic acidsin the formation during heating/pyrolyzation. In certain embodiments,hydrocarbon fluids produced from a formation have acid numbers less thanabout 1 mg/gram KOH, less than about 0.8 mg/gram KOH, less than about0.6 mg/gram KOH, less than about 0.5 mg/gram KOH, less than about 0.25mg/gram KOH, or less than about 0.1 mg/gram KOH.

[1387] In certain embodiments, a portion of the formation proximate aproduction well may be hotter than other portions of the formation(e.g., an average temperature above about 300° C.). The increasedtemperature of the portion of the formation proximate the productionwell may be produced by additional heat provided by a heater placedwithin the production well, an additional heat source proximate theproduction well, and/or natural heating within the portion. Having anincreased temperature in the portion proximate the production well mayincrease and/or upgrade a quality of hydrocarbons produced through theproduction well (e.g., by increased cracking or thermal upgrading of thehydrocarbons). In addition, a quality of hydrocarbons produced may befurther increased by cracking of hydrocarbons or reaction ofhydrocarbons within the production well.

[1388] Increasing heating proximate a production well, however, mayincrease the possibility of coking at the production well. In someembodiments, operating conditions within the formation may be controlledto inhibit coking of a production well. In one embodiment, heat outputfrom a heat source proximate the production well may be controlled toinhibit coking of the production well. For example, the heat source canbe turned down and/or off when conditions (e.g., temperature) at theproduction well begin to favor coking at the production well. Forexample, coke may form at temperatures above about 400° C. In certainembodiments, heat provided from the heat source may be turned downand/or off during a time at which a mixture is produced through theproduction well. The heat provided may be turned on and/or increasedwhen the quality of produced fluid is below a desired quality. Inanother embodiment, a production well is located at a sufficientdistance from each of the heat sources in the formation such that atemperature at the production well inhibits coking at the productionwell.

[1389] In other embodiments, steam may be added to the formation byadding water or steam through a conduit in a production well or otherwellbore. In some embodiments, steam may be produced by evaporation ofwater within the formation. The additional steam may inhibit cokeformation proximate the production well. The steam may react with thecoke to form carbon dioxide, carbon monoxide, and/or hydrogen. Incertain embodiments, air may be periodically injected through a conduit(e.g., a conduit in a production well) to oxidize any coke formed at ornear a production well.

[1390] In an embodiment of a system using heat sources, a material(e.g., a cement and/or polymer foam) may be injected into the formationto inhibit fingering and/or breakthrough of gases within the formation.The material may inhibit fluid flow through channels adjacent to theheat sources. The use of such a material may provide a more uniform flowof mobilized fluids and increase the recovery of fluids from theformation.

[1391] Several patterns of heat sources arranged in rings aroundproduction wells may be utilized to create a pyrolysis region around aproduction well and a low viscosity zone in an oil shale formation.Various pattern embodiments are shown in FIGS. 136-148.

[1392] Production wells 2701 and heat sources 2712 may be located at theapices of a triangular grid, as depicted in FIG. 136. The triangulargrid may be an equilateral triangular grid with sides of length s.Production wells 2701 may be spaced at a distance of about 1.732(s).Each production well 2701 may be disposed at a center of ring 2713 ofheat sources 2712 in a hexagonal pattern. Each heat source 2712 mayprovide substantially equal amounts of heat to three production wells.Therefore, each ring 2713 of six heat sources 2712 may contributeapproximately two equivalent heat sources per production well 2701.

[1393]FIG. 137 illustrates a pattern of production wells 2701 with aninner hexagonal ring 2713 and an outer hexagonal ring 2715 of heatsources 2712. In this pattern, production wells 2701 may be spaced at adistance of about 2(1.732)s. Heat sources 2712 may be located at allother grid positions. This pattern may result in a ratio of equivalentheat sources to production wells that may approach 11:1 (i.e., 6equivalent heat sources for ring 2713; ({fraction (1/2)})(6) or 3equivalent heat sources for the 6 heat sources of ring 2715 betweenapices of the hexagonal pattern; and ({fraction (1/3)})(6) or 2equivalent heat sources for the 6 heat sources of ring 2715 at theapices of the hexagonal pattern).

[1394]FIG. 138 illustrates three rings of heat sources 2712 surroundingproduction well 2701. Production well 2701 may be surrounded by ring2713 of six heat sources 2712. Second hexagonally shaped ring 2716 oftwelve heat sources 2712 may surround ring 2713. Third ring 2718 of heatsources 2712 may include twelve heat sources that may providesubstantially equal amounts of heat to two production wells and six heatsources that may provide substantially equal amounts of heat to threeproduction wells. Therefore, a total of eight equivalent heat sourcesmay be disposed on third ring 2718. Production well 2701 may be providedheat from an equivalent of about twenty-six heat sources. FIG. 139illustrates an even larger pattern that may have a greater spacingbetween production wells 2701.

[1395]FIGS. 140, 141, 142, and 143 illustrate embodiments in which bothproduction wells and heat sources are located at the apices of atriangular grid. In FIG. 140, a triangular grid with a spacing of s mayhave production wells 2701 spaced at a distance of 2s. A hexagonalpattern may include one ring 2730 of six heat sources 2732. Each heatsource 2732 may provide substantially equal amounts of heat to twoproduction wells 2701. Therefore, each ring 2730 of six heat sources2732 contributes approximately three equivalent heat sources perproduction well 2701.

[1396]FIG. 141 illustrates a pattern of production wells 2701 with innerhexagonal ring 2734 and outer hexagonal ring 2736. Production wells 2701may be spaced at a distance of 3s. Heat sources 2732 may be located atapices of hexagonal ring 2734 and hexagonal ring 2736. Hexagonal ring2734 and hexagonal ring 2736 may include six heat sources each. Thepattern in FIG. 141 may result in a ratio of heat sources 2732 toproduction well 2701 of about eight.

[1397]FIG. 142 illustrates a pattern of production wells 2701 also withtwo hexagonal rings of heat sources surrounding each production well.Production well 2701 may be surrounded by ring 2738 of six heat sources2732. Production wells 2701 may be spaced at a distance of 4s. Secondhexagonal ring 2740 may surround ring 2738. Second hexagonal ring 2740may include twelve heat sources 2732. This pattern may result in a ratioof heat sources 2732 to production wells 2701 that may approach fifteen.

[1398]FIG. 143 illustrates a pattern of heat sources 2732 with threerings of heat sources 2732 surrounding each production well 2701.Production wells 2701 may be surrounded by ring 2742 of six heat sources2732. Second ring 2744 of twelve heat sources 2732 may surround ring2742. Third ring 2746 of heat sources 2732 may surround second ring2744. Third ring 2746 may include 6 equivalent heat sources. Thispattern may result in a ratio of heat sources 2732 to production wells2701 that is about 24:1.

[1399]FIGS. 144, 145, 146, and 147 illustrate patterns in which theproduction well may be disposed at a center of a triangular grid suchthat the production well may be equidistant from the apices of thetriangular grid. In FIG. 144, the triangular grid of heater wells with aspacing of s may include production wells 2760 spaced at a distance ofs. Each production well 2760 may be surrounded by ring 2764 of threeheat sources 2762. Each heat source 2762 may provide substantially equalamounts of heat to three production wells 2760. Therefore, each ring2764 of three heat sources 2762 may contribute one equivalent heatsource per production well 2760.

[1400]FIG. 145 illustrates a pattern of production wells 2760 with innertriangular ring 2766 and outer hexagonal ring 2768. In this pattern,production wells 2760 may be spaced at a distance of 2s. Heat sources2762 may be located at apices of inner triangular ring 2766 and outerhexagonal ring 2768. Inner triangular ring 2766 may contribute threeequivalent heat sources per production well 2760. Outer hexagonal ring2768 containing three heater wells may contribute one equivalent heatsource per production well 2760. Thus, a total of four equivalent heatsources may provide heat to production well 2760.

[1401]FIG. 146 illustrates a pattern of production wells with one innertriangular ring of heat sources surrounding each production well and oneirregular hexagonal outer ring. Production wells 2760 may be surroundedby ring 2770 of three heat sources 2762. Production wells 2760 may bespaced at a distance of 3s. Irregular hexagonal ring 2772 of nine heatsources 2762 may surround ring 2770. This pattern may result in a ratioof heat sources 2762 to production wells 2760 of about 9:1.

[1402]FIG. 147 illustrates triangular patterns of heat sources withthree rings of heat sources surrounding each production well. Productionwells 2760 may be surrounded by ring 2774 of three heat sources 2762.Irregular hexagon pattern 2776 of nine heat sources 2762 may surroundring 2774. Third set 2778 of heat sources 2762 may surround irregularhexagonal pattern 2776. Third set 2778 may contribute four equivalentheat sources to production well 2760. A ratio of equivalent heat sourcesto production well 2760 may be sixteen.

[1403]FIG. 148 depicts an embodiment of a pattern of heat sources 2705arranged in a triangular pattern. Production well 2701 may be surroundedby triangles 2780, 2782, and 2784 of heat sources 2705. Heat sources2705 in triangles 2780, 2782, and 2784 may provide heat to theformation. The provided heat may raise an average temperature of theformation to a pyrolysis temperature. Pyrolyzation fluids may flow toproduction well 2701. Formation fluids may be produced in productionwell 2701.

[1404]FIG. 149 illustrates an example of a square pattern of heatsources 3000 and production wells 3002. Heat sources 3000 are disposedat vertices of squares 3010. Production well 3002 is placed in a centerof every third square in both x- and y-directions. Midlines 3006 areformed equidistant to two production wells 3002, and perpendicular to aline connecting such production wells. Intersections of midlines 3006 atvertices 3008 form unit cell 3012. Heat source 3000 a is completelywithin unit cell 3012. Heat source 3000 b and heat source 3000 c areonly partially within unit cell 3012. Only the one-half fraction of heatsource 3000 b and the one-quarter fraction of heat source 3000 c withinunit cell 3012 provide heat within unit cell 3012. The fraction of heatsource 3000 outside of unit cell 3012 may provide heat outside of unitcell 3012. The number of heat sources 3000 within one unit cell 3012 isa ratio of heat sources 3000 per production well 3002 within theformation.

[1405] The total number of heat sources inside unit cell 3012 may bedetermined by the following method:

[1406] (a) 4 heat sources 3000 a inside unit cell 3012 are counted asone heat source each;

[1407] (b) 8 heat sources 3000 b on midlines 3006 are counted asone-half heat source each; and

[1408] (c) 4 heat sources 3000 c at vertices 3008 are counted asone-quarter heat source each.

[1409] The total number of heat sources is determined from adding theheat sources counted by, (a) 4, (b)8/2=4, and (c) 4/4=1, for a totalnumber of 9 heat sources 3000 in unit cell 3012. Therefore, a ratio ofheat sources 3000 to production wells 3002 is determined as 9:1 for thepattern illustrated in FIG. 149.

[1410]FIG. 150 illustrates an example of another pattern of heat sources3000 and production wells 3002. Midlines 3006 are formed equidistantfrom two production wells 3002, and perpendicular to a line connectingsuch production wells. Unit cell 3014 is determined by intersection ofmidlines 3006 at vertices 3008. Twelve heat sources 3000 are counted inunit cell 3014, of which six are whole sources of heat, and six areone-third sources of heat (with the other two-thirds of heat from suchsix wells going to other patterns). Thus, a ratio of heat sources 3000to production wells 3002 is determined as 8:1 for the patternillustrated in FIG. 150.

[1411]FIG. 151 illustrates an embodiment of triangular pattern 3100 ofheat sources 3102. FIG. 152 illustrates an embodiment of square pattern3101 of heat sources 3103. FIG. 153 illustrates an embodiment ofhexagonal pattern 3104 of heat sources 3106. FIG. 154 illustrates anembodiment of 12:1 pattern 3105 of heat sources 3107. A temperaturedistribution for all patterns may be determined by an analytical method.The analytical method may be simplified by analyzing only temperaturefields within “confined” patterns (e.g., hexagons), i.e., completelysurrounded by others. In addition, the temperature field may beestimated to be a superposition of analytical solutions corresponding toa single heat source.

[1412]FIG. 155 illustrates a schematic diagram of an embodiment ofsurface facilities 2800 that may treat a formation fluid. The formationfluid may be produced though a production well. As shown in FIG. 155,surface facilities 2800 may be coupled to separator 2802. Separator mayreceive formation fluid produced from an oil shale formation during anin situ conversion process. Separator 2802 may separate the formationfluid into gas stream 2804, liquid hydrocarbon condensate stream 2806,and water stream 2808.

[1413] Water stream 2808 may flow from separator 2802 to a portion of aformation, to a containment system, or to a processing unit. Forexample, water stream 2808 may flow from separator 2802 to an ammoniaproduction unit. Ammonia produced in the ammonia production unit mayflow to an ammonium sulfate unit. The ammonium sulfate unit may combinethe ammonia with H₂SO₄ or SO₂/SO₃ to produce ammonium sulfate. Inaddition, ammonia produced in the ammonia production unit may flow to aurea production unit. The urea production unit may combine carbondioxide with the ammonia to produce urea.

[1414] Gas stream 2804 may flow through a conduit from separator 2802 togas treatment unit 2810. The gas treatment unit may separate variouscomponents of gas stream 2804. For example, the gas treatment unit mayseparate gas stream 2804 into carbon dioxide stream 2812, hydrogensulfide stream 2814, hydrogen stream 2816, and stream 2818 that mayinclude, but is not limited to, methane, ethane, propane, butanes(including n-butane or isobutane), pentane, ethene, propene, butene,pentene, water, or combinations thereof.

[1415] The carbon dioxide stream may flow through a conduit to aformation, to a containment system, to a disposal unit, and/or toanother processing unit. In addition, the hydrogen sulfide stream mayalso flow through a conduit to a containment system and/or to anotherprocessing unit. For example, the hydrogen sulfide stream may beconverted into elemental sulfur in a Claus process unit. The gastreatment unit may separate gas stream 2804 into stream 2819. Stream2819 may include heavier hydrocarbon components from gas stream 2804.Heavier hydrocarbon components may include, for example, hydrocarbonshaving a carbon number of greater than about 5. Heavier hydrocarboncomponents in stream 2819 may be provided to liquid hydrocarboncondensate stream 2806.

[1416] Surface facilities 2800 may also include processing unit 2821.Processing unit 2821 may separate stream 2818 into a number of streams.Each of the streams may be rich in a predetermined component or apredetermined number of compounds. For example, processing unit 2821 mayseparate stream 2818 into first portion 2820 of stream 2818, secondportion 2823 of stream 2818, third portion 2825 of stream 2818, andfourth portion 2831 of stream 2818. First portion 2820 of stream 2818may include lighter hydrocarbon components such as methane and ethane.First portion 2820 of stream 2818 may flow from gas treatment unit 2810to power generation unit 2822.

[1417] Power generation unit 2822 may extract useable energy from thefirst portion of stream 2818. For example, stream 2818 may be producedunder pressure. Power generation unit 2822 may include a turbine thatgenerates electricity from the first portion of stream 2818. The powergeneration unit may also include, for example, a molten carbonate fuelcell, a solid oxide fuel cell, or other type of fuel cell. The extracteduseable energy may be provided to user 2824. User 2824 may include, forexample, surface facilities 2800, a heat source disposed within aformation, and/or a consumer of useable energy.

[1418] Second portion 2823 of stream 2818 may also include lighthydrocarbon components. For example, second portion 2823 of stream 2818may include, but is not limited to, methane and ethane. Second portion2823 of stream 2818 may be provided to natural gas pipeline 2827.Alternatively, second portion 2823 of stream 2818 may be provided to alocal market. The local market may be a consumer market or a commercialmarket. Second portion 2823 of stream 2818 may be used as an end productor an intermediate product depending on, for example, a composition ofthe light hydrocarbon components.

[1419] Third portion 2825 of stream 2818 may include liquefied petroleumgas (“LPG”). Major constituents of LPG may include hydrocarbonscontaining three or four carbon atoms such as propane and butane. Butanemay include n-butane or isobutane. LPG may also include relatively smallconcentrations of other hydrocarbons, such as ethene, propene, butene,and pentene. Some LPG may also include additional components. LPG may bea gas at atmospheric pressure and normal ambient temperatures. LPG maybe liquefied, however, when moderate pressure is applied or when thetemperature is sufficiently reduced. When such moderate pressure isreleased, LPG gas may have about 250 times a volume of LPG liquid.Therefore, large amounts of energy may be stored and transportedcompactly as LPG.

[1420] Third portion 2825 of stream 2818 may be provided to local market2829. The local market may include a consumer market or a commercialmarket. Third portion 2825 of stream 2818 may be used as an end productor an intermediate product. LPG may be used in applications, such asfood processing, aerosol propellants, and automotive fuel. LPG may beprovided in for standard heating and cooking purposes as commercialpropane and/or commercial butane. Propane may be more versatile forgeneral use than butane because propane has a lower boiling point thanbutane.

[1421] Fourth portion 2831 of stream 2818 may flow from the gastreatment unit to hydrogen manufacturing unit 2828. Hydrogen-rich stream2830 is shown exiting hydrogen manufacturing unit 2828. Examples ofhydrogen manufacturing unit 2828 may include a steam reformer and acatalytic flameless distributed combustor with a hydrogen separationmembrane.

[1422]FIG. 156 illustrates an embodiment of a catalytic flamelessdistributed combustor. An example of a catalytic flameless distributedcombustor with a hydrogen separation membrane is illustrated in U.S.Patent Application No. 60/273,354, filed on Mar. 5, 2001, which isincorporated by reference as if fully set forth herein. A catalyticflameless distributed combustor may include fuel line 2850, oxidant line2852, catalyst 2854, and membrane 2856. Fourth portion 2831 of stream2818 (shown in FIG. 155) may be provided to hydrogen manufacturing unit2828 as fuel 2858. Fuel 2858 within fuel line 2850 may mix withinreaction volume in annular space 2859 between the fuel line and theoxidant line. Reaction of the fuel with the oxidant in the presence ofcatalyst 2854 may produce reaction products that include H₂. Membrane2856 may allow a portion of the generated H₂ to pass into annular space2860 between outer wall 2862 of oxidant line 2852 and membrane 2856.Excess fuel passing out of fuel line 2850 may be circulated back toentrance of hydrogen manufacturing unit 2828. Combustion productsleaving oxidant line 2852 may include carbon dioxide and other reactionsproducts as well as some fuel and oxidant. The fuel and oxidant may beseparated and recirculated back to the hydrogen manufacturing unit.Carbon dioxide may be separated from the exit stream. The carbon dioxidemay be sequestered within a portion of a formation or used for analternate purpose.

[1423] Fuel line 2850 may be concentrically positioned within oxidantline 2852. Critical flow orifices 2863 within fuel line 2850 may allowfuel to enter into a reaction volume in annular space 2859 between thefuel line and oxidant line 2852. The fuel line may carry a mixture ofwater and vaporized hydrocarbons such as, but not limited to, methane,ethane, propane, butane, methanol, ethanol, or combinations thereof. Theoxidant line may carry an oxidant such as, but not limited to, air,oxygen enriched air, oxygen, hydrogen peroxide, or combinations thereof.

[1424] Catalyst 2854 may be located in the reaction volume to allowreactions that produce H₂ to proceed at relatively low temperatures.Without a catalyst and without membrane separation of H₂, a steamreformation reaction may need to be conducted in a series of reactorswith temperatures for a shift reaction occurring in excess of 980° C.With a catalyst and with separation of H₂ from the reaction stream, thereaction may occur at temperatures within a range from about 300° C. toabout 600° C., or within a range from about 400° C. to about 500° C.Catalyst 2854 may be any steam reforming catalyst. In selectedembodiments, catalyst 2854 is a group VIII transition metal, such asnickel. The catalyst may be supported on porous substrate 2864. Thesubstrate may include group III or group IV elements, such as, but notlimited to, aluminum, silicon, titanium, or zirconium. In an embodiment,the substrate is alumina (Al₂O₃).

[1425] Membrane 2856 may remove H₂ from a reaction stream within areaction volume of a hydrogen manufacturing unit 2828. When H₂ isremoved from the reaction stream, reactions within the reaction volumemay generate additional H₂. A vacuum may draw H₂ from an annular regionbetween membrane 2856 and outer wall 2862 of oxidant line 2852.Alternately, H₂ may be removed from the annular region in a carrier gas.Membrane 2856 may separate H₂ from other components within the reactionstream. The other components may include, but are not limited to,reaction products, fuel, water, and hydrogen sulfide. The membrane maybe a hydrogen-permeable and hydrogen selective material such as, but notlimited to, a ceramic, carbon, metal, or combination thereof. Themembrane may include, but is not limited to, metals of group VIII, V,III, or I such as palladium, platinum, nickel, silver, tantalum,vanadium, yttrium, and/or niobium. The membrane may be supported on aporous substrate such as alumina. The support may separate the membrane2856 from catalyst 2854. The separation distance and insulationproperties of the support may help to maintain the membrane within adesired temperature range.

[1426] Hydrogen manufacturing unit 2828 of the surface facilitiesembodiment depicted in FIG. 155 may produce hydrogen-rich stream 2830from the second portion stream 2818. Hydrogen-rich stream 2830 may flowinto hydrogen stream 2816 to form stream 2832. Stream 2832 may include alarger volume of hydrogen than either hydrogen-rich stream 2830 orhydrogen stream 2816.

[1427] Hydrocarbon condensate stream 2806 may flow through a conduitfrom wellhead 2803 to hydrotreating unit 2834. Hydrotreating unit 2834may hydrogenate hydrocarbon condensate stream 2806 to form hydrogenatedhydrocarbon condensate stream 2836. The hydrotreater may upgrade andswell the hydrocarbon condensate. Surface facilities 2800 may providestream 2832 (which includes a relatively high concentration of hydrogen)to hydrotreating unit 2834. H₂ in stream 2832 may hydrogenate a doublebond of the hydrocarbon condensate, thereby reducing a potential forpolymerization of the hydrocarbon condensate. In addition, hydrogen mayalso neutralize radicals in the hydrocarbon condensate. The hydrogenatedhydrocarbon condensate may include relatively short chain hydrocarbonfluids. Furthermore, hydrotreating unit 2834 may reduce sulfur,nitrogen, and aromatic hydrocarbons in hydrocarbon condensate stream2806. Hydrotreating unit 2834 may be a deep hydrotreating unit or a mildhydrotreating unit. An appropriate hydrotreating unit may vary dependingon, for example, a composition of stream 2832, a composition of thehydrocarbon condensate stream, and/or a selected composition of thehydrogenated hydrocarbon condensate stream.

[1428] Hydrogenated hydrocarbon condensate stream 2836 may flow fromhydrotreating unit 2834 to transportation unit 2838. Transportation unit2838 may collect a volume of the hydrogenated hydrocarbon condensateand/or to transport the hydrogenated hydrocarbon condensate to marketcenter 2840. Market center 2840 may include, but is not limited to, aconsumer marketplace or a commercial marketplace. A commercialmarketplace may include a refinery. The hydrogenated hydrocarboncondensate may be used as an end product or an intermediate product.

[1429] Alternatively, hydrogenated hydrocarbon condensate stream 2836may flow to a splitter or an ethene production unit. The splitter mayseparate the hydrogenated hydrocarbon condensate stream into ahydrocarbon stream including components having carbon numbers of 5 or 6,a naphtha stream, a kerosene stream, and/or a diesel stream. Selectedstreams exiting the splitter may be fed to the ethene production unit.In addition, the hydrocarbon condensate stream and the hydrogenatedhydrocarbon condensate stream may be fed to the ethene production unit.Ethene produced by the ethene production unit may be fed to apetrochemical complex to produce base and industrial chemicals andpolymers. Alternatively, the streams exiting the splitter may be fed toa hydrogen conversion unit. A recycle stream may flow from the hydrogenconversion unit to the splitter. The hydrocarbon stream exiting thesplitter and the naphtha stream may be fed to a mogas production unit.The kerosene stream and the diesel stream may be distributed as product.

[1430]FIG. 157 illustrates an embodiment of an additional processingunit that may be included in surface facilities 2800, such as thefacilities depicted in FIG. 155. Air 2903 may be fed to air separationunit 2900. Air separation unit 2900 may generate nitrogen stream 2902and oxygen stream 2905. Oxygen stream 2905 and steam 2904 may beinjected into exhausted resource 2906 to generate synthesis gas 2907.Produced synthesis gas 2907 may be provided to Shell Middle Distillatesprocess unit 2910 that produces middle distillates 2912. In addition,produced synthesis gas 2907 may be provided to catalytic methanationprocess unit 2914 that produces natural gas 2916. Produced synthesis gas2907 may also be provided to methanol production unit 2918 to producemethanol 2920. Produced synthesis gas 2907 may be provided to processunit 2922 for production of ammonia and/or urea 2924. Synthesis gas maybe used as a fuel for fuel cell 2926 that produces electricity 2928.Synthesis gas 2907 may also be routed to power generation unit 2930,such as a turbine or combustor, to produce electricity 2932.

[1431] The comparisons of patterns of heat sources were evaluated forthe same heater well density and the same heating input regime. Forexample, a number of heat sources per unit area in a triangular patternis the same as the number of heat sources per unit area in the 10 mhexagonal pattern if the space between heat sources is increased toabout 12.2 m in the triangular pattern. The equivalent spacing for asquare pattern would be 11.3 m, while the equivalent spacing for a 12:1pattern would be 15.7 m.

[1432]FIG. 158 illustrates temperature profile 3110 after three years ofheating for a triangular pattern with a 12.2 m spacing in a typicalGreen River oil shale. FIG. 151 depicts an embodiment of a triangularpattern. Temperature profile 3110 is a three-dimensional plot oftemperature versus a location within a triangular pattern. FIG. 159illustrates temperature profile 3108 after three years of heating for asquare pattern with 11.3 m spacing in a typical Green River oil shale.Temperature profile 3108 is a three-dimensional plot of temperatureversus a location within a square pattern. FIG. 152 depicts anembodiment of a square pattern. FIG. 160 illustrates temperature profile3109 after three years of heating for a hexagonal pattern with 10.0 mspacing in atypical Green River oil shale. Temperature profile 3109 is athree-dimensional plot of temperature versus a location within ahexagonal pattern. FIG. 153 depicts an embodiment of a hexagonalpattern.

[1433] As shown in a comparison of FIGS. 158, 159, and 160, atemperature profile of the triangular pattern is more uniform than atemperature profile of the square or hexagonal pattern. For example, aminimum temperature of the square pattern is approximately 280° C., anda minimum temperature of the hexagonal pattern is approximately 250° C.In contrast, a minimum temperature of the triangular pattern isapproximately 300° C. Therefore, a temperature variation within thetriangular pattern after 3 years of heating is 20° C. less than atemperature variation within the square pattern and 50° C. less than atemperature variation within the hexagonal pattern. For a chemicalprocess, where reaction rate is proportional to an exponent oftemperature, a 20° C. difference may have a substantial effect onproducts being produced in a pyrolysis zone.

[1434]FIG. 161 illustrates a comparison plot between the average patterntemperature (in degrees Celsius) and temperatures at the coldest spotsfor each pattern as a function of time (in years). The coldest spot foreach pattern is located at a pattern center (centroid). As shown in FIG.151, the coldest spot of a triangular pattern is point 3118, while point3117 is the coldest spot of a square pattern, as shown in FIG. 152. Asshown in FIG. 153, the coldest spot of a hexagonal pattern is point3114, while point 3115 is the coldest spot of a 12:1 pattern, as shownin FIG. 154. The difference between an average pattern temperature andtemperature of the coldest spot represents how uniform the temperaturedistribution for a given pattern is. The more uniform the heating, thebetter the product quality that may be made in the formation. The largerthe volume fraction of resource that is overheated, the greater theamount of undesirable product tends to be made.

[1435] As shown in FIG. 161, the difference between average temperature3120 of a pattern and temperature of the coldest spot is less fortriangular pattern 3118 than for square pattern 3117, hexagonal pattern3114, or 12:1 pattern 3115. Again, there is a substantial differencebetween triangular and hexagonal patterns.

[1436] Another way to assess the uniformity of temperature distributionis to compare temperatures of the coldest spot of a pattern with a pointlocated at the center of a side of a pattern midway between heaters. Asshown in FIG. 153, point 3112 is located at the center of a side of thehexagonal pattern midway between heaters. As shown in FIG. 151, point3116 is located at the center of a side of a triangular pattern midwaybetween heaters. Point 3119 is located at the center of a side of thesquare pattern midway between heaters, as shown in FIG. 152.

[1437]FIG. 162 illustrates a comparison plot between average patterntemperature 3120 (in degrees Celsius), temperatures at coldest spot 3118for triangular patterns, coldest spot 3114 for hexagonal patterns, point3116 located at the center of a side of triangular pattern midwaybetween heaters, and point 3112 located at the center of a side ofhexagonal pattern midway between heaters, as a function of time (inyears). FIG. 163 illustrates a comparison plot between average patterntemperature 3120 (in degrees Celsius), temperatures at coldest spot 3117and point 3119 located at the center of a side of a pattern midwaybetween heaters, as a function of time (in years), for a square pattern.

[1438] As shown in a comparison of FIGS. 162 and 163, for each pattern,a temperature at a center of a side midway between heaters is higherthan a temperature at a center of the pattern. A difference between atemperature at a center of a side midway between heaters and a center ofthe hexagonal pattern increases substantially during the first year ofheating, and stays relatively constant afterward. A difference between atemperature at an outer lateral boundary and a center of the triangularpattern, however, is negligible. Therefore, a temperature distributionin a triangular pattern is more uniform than a temperature distributionin a hexagonal pattern. A square pattern also provides more uniformtemperature distribution than a hexagonal pattern, however, it is stillless uniform than a temperature distribution in a triangular pattern.

[1439] A triangular pattern of heat sources may have, for example, ashorter total process time than a square, hexagonal, or 12:1 pattern ofheat sources for the same heater well density. A total process time mayinclude a time required for an average temperature of a heated portionof a formation to reach a target temperature and a time required for atemperature at a coldest spot within the heated portion to reach thetarget temperature. For example, heat may be provided to the portion ofthe formation until an average temperature of the heated portion reachesthe target temperature. After the average temperature of the heatedportion reaches the target temperature, an energy supply to the heatsources may be reduced such that less or minimal heat may be provided tothe heated portion. An example of a target temperature may beapproximately 340° C. The target temperature, however, may varydepending on, for example, formation composition and/or formationconditions such as pressure.

[1440]FIG. 164 illustrates a comparison plot between the average patterntemperature and temperatures at the coldest spots for each pattern, as afunction of time when heaters are turned off after the averagetemperature reaches a target value. As shown in FIG. 164, averagetemperature 3120 of the formation reaches a target temperature (about340° C.) in approximately 3 years. As shown in FIG. 164, a temperatureat the coldest point within the triangular pattern 3118 reaches thetarget temperature (about 340° C.) about 0.8 years later. A totalprocess time for such a triangular pattern is about 3.8 years when theheat input is discontinued when the target average temperature isreached. As shown in FIG. 164, a temperature at the coldest point withinthe triangular pattern reaches the target temperature (about 340° C.)before a temperature at coldest point within the square pattern 3117 ora temperature at the coldest point within the hexagonal pattern 3114reaches the target temperature. A temperature at the coldest pointwithin the hexagonal pattern, however, reaches the target temperatureafter an additional time of about 2 years when the heaters are turnedoff upon reaching the target average temperature. Therefore, a totalprocess time for a hexagonal pattern is about 5.0 years. A total processtime for heating a portion of a formation with a triangular pattern is1.2 years less (approximately 25% less) than a total process time forheating a portion of a formation with a hexagonal pattern. In anembodiment, the power to the heaters may be reduced or turned off whenthe average temperature of the pattern reaches a target level. Thisprevents overheating the resource, which wastes energy and produceslower product quality. The triangular pattern has the most uniformtemperatures and the least overheating. Although a capital cost of sucha triangular pattern may be approximately the same as a capital cost ofthe hexagonal pattern, the triangular pattern may accelerate oilproduction and require a shorter total process time.

[1441] A triangular pattern may be more economical than a hexagonalpattern. A spacing of heat sources in a triangular pattern that willhave about the same process time as a hexagonal pattern having about a10.0 m space between heat sources may be equal to approximately 14.3 m.The triangular pattern may include about 26% less heat sources than theequivalent hexagonal pattern. Using the triangular pattern may allow forlower capital cost (i.e., there are fewer heat sources and productionwells) and lower operating costs (i.e., there are fewer heat sources andproduction wells to power and operate).

[1442]FIG. 59 depicts an embodiment of a natural distributed combustor.In one experiment, the embodiment schematically shown in FIG. 59 wasused to heat high volatile bituminous C coal in situ. A portion of aformation was heated with electrical resistance S heaters and/or anatural distributed combustor. Thermocouples were located every 2 feetalong the length of the natural distributed combustor (along conduit 532schematically shown in FIG. 59). The coal was first heated withelectrical resistance heaters until pyrolysis was complete near thewell. FIG. 165 depicts square data points measured during electricalresistance heating at various depths in the coal after the temperatureprofile had stabilized (the coal seam was about 16 feet thick startingat about 28 feet of depth). At this point heat energy was being suppliedat about 300 watts per foot. Air was subsequently injected via conduit532 at gradually increasing rates, and electric power supplied to theelectrical resistance heaters was decreased. Combustion products wereremoved from the reaction volume through an annular space betweenconduit 532 and a well casing. The power supplied to the electricalresistance heaters was decreased at a rate that would approximatelyoffset heating provided by the combustion of the coal adjacent toconduit 532. Air input was increased and power input was decreased overa period of about 2 hours until no electric power was being supplied.

[1443] Diamond data points of FIG. 165 depict temperature as a functionof depth for natural distributed combustion heating (without anyelectrical resistance heating) in the coal after the temperature profilehad substantially stabilized. As can be seen in FIG. 165, the naturaldistributed combustion heating provided a temperature profile that iscomparable to the electrical resistance temperature profile (representedby square data points). This experiment demonstrated that naturaldistributed combustors may provide formation heating that is comparableto the formation heating provided by electrical resistance heaters. Thisexperiment was repeated at different temperatures and in two otherwells, all with similar results.

[1444] Numerical calculations have been made for a natural distributedcombustor system that heats a hydrocarbon containing formation. Acommercially available program called PRO-II (Simulation Sciences Inc.,Brea, Calif.) was used to make example calculations based on a conduitof diameter 6.03 cm with a wall thickness of 0.39 cm. The conduit wasdisposed in an opening in the formation with a diameter of 14.4 cm. Theconduit had critical flow orifices of 1.27 mm diameter spaced 183 cmapart. The conduit heated a formation of 91.4 m thickness. A flow rateof air was 1.70 standard cubic meters per minute through the criticalflow orifices. Pressure of air at the inlet of the conduit was 7 barsabsolute. Exhaust gases had a pressure of 3.3 bars absolute. A heatingoutput of 1066 watts per meter was used. A temperature in the openingwas set at 760° C. The calculations determined a minimal pressure dropwithin the conduit of about 0.023 bars. The pressure drop within theopening was less than 0.0013 bars.

[1445]FIG. 166 illustrates extension (in meters) of a reaction zonewithin a coal formation over time (in years) according to the parametersset in the calculations. The width of the reaction zone increases withtime due to oxidation of carbon adjacent to the conduit.

[1446] Numerical calculations have been made for heat transfer using aconductor-in-conduit heater. Calculations were made for a conductorhaving a diameter of about 1 inch (2.54 cm) disposed in a conduit havinga diameter of about 3 inches (7.62 cm). The conductor-in-conduit heaterwas disposed in an opening of a carbon containing formation having adiameter of about 6 inches (15.24 cm). An emissivity of the carboncontaining formation was maintained at a value of 0.9, which is expectedfor geological materials. The conductor and the conduit were givenalternate emissivity values of high emissivity (0.86), which is commonfor oxidized metal surfaces, and low emissivity (0.1), which is forpolished and/or un-oxidized metal surfaces. The conduit was filled witheither air or helium. Helium is known to be a more thermally conductivegas than air. The space between the conduit and the opening was filledwith a gas mixture of methane, carbon dioxide, and hydrogen gases.

[1447] Two different gas mixtures were used. The first gas mixture hadmole fractions of 0.5 for methane, 0.3 for carbon dioxide, and 0.2 forhydrogen. The second gas mixture had mole fractions of 0.2 for methane,0.2 for carbon dioxide, and 0.6 for hydrogen.

[1448]FIG. 167 illustrates a calculated ratio of conductive heattransfer to radiative heat transfer versus a temperature of a face ofthe carbon containing formation in the opening for an air filledconduit. The temperature of the conduit was increased linearly from 93°C. to 871° C. The ratio of conductive to radiative heat transfer wascalculated based on emissivity values, thermal conductivities,dimensions of the conductor, conduit, and opening, and the temperatureof the conduit. Line 3204 is calculated for the low emissivity value(0.1). Line 3206 is calculated for the high emissivity value (0.86). Alower emissivity for the conductor and the conduit provides for a higherratio of conductive to radiative heat transfer to the formation. Thedecrease in the ratio with an increase in temperature may be due to areduction of conductive heat transfer with increasing temperature. Asthe temperature on the face of the formation increases, a temperaturedifference between the face and the heater is reduced, thus reducing atemperature gradient that drives conductive heat transfer.

[1449]FIG. 168 illustrates a calculated ratio of conductive heattransfer to radiative heat transfer versus a temperature at a face ofthe carbon containing formation in the opening for a helium filledconduit. The temperature of the conduit was increased linearly from 93°C. to 871° C. The ratio of conductive to radiative heat transfer wascalculated based on emissivity values; thermal conductivities;dimensions of the conductor, conduit, and opening; and the temperatureof the conduit. Line 3208 is calculated for the low emissivity value(0.1). Line 3210 is calculated for the high emissivity value (0.86). Alower emissivity for the conductor and the conduit again provides for ahigher ratio of conductive to radiative heat transfer to the formation.The use of helium instead of air in the conduit significantly increasesthe ratio of conductive heat transfer to radiative heat transfer. Thismay be due to a thermal conductivity of helium being about 5.2 to about5.3 times greater than a thermal conductivity of air.

[1450]FIG. 169 illustrates temperatures of the conductor, the conduit,and the opening versus a temperature at a face of the carbon containingformation for a helium filled conduit and a high emissivity of 0.86. Theopening has a gas mixture equivalent to the second mixture describedabove having a hydrogen mole fraction of 0.6. Opening temperature 3216was linearly increased from 93° C. to 871° C. Opening temperature 3216was assumed to be the same as the temperature at the face of the carboncontaining formation. Conductor temperature 3212 and conduit temperature3214 were calculated from opening temperature 3216 using the dimensionsof the conductor, conduit, and opening, values of emissivities for theconductor, conduit, and face, and thermal conductivities for gases(helium, methane, carbon dioxide, and hydrogen). It may be seen from theplots of temperatures of the conductor, conduit, and opening for theconduit filled with helium, that at higher temperatures approaching 871°C., the temperatures of the conductor, conduit, and opening begin toequilibrate.

[1451]FIG. 170 illustrates temperatures of the conductor, the conduit,and the opening versus a temperature at a face of the carbon containingformation for an air filled conduit and a high emissivity of 0.86. Theopening has a gas mixture equivalent to the second mixture describedabove having a hydrogen mole fraction of 0.6. Opening temperature 3216was linearly increased from 93° C. to 871° C. Opening temperature 3216was assumed to be the same as the temperature at the face of the carboncontaining formation. Conductor temperature 3212 and conduit temperature3214 were calculated from opening temperature 3216 using the dimensionsof the conductor, conduit, and opening, values of emissivities for theconductor, conduit, and face, and thermal conductivities for gases (air,methane, carbon dioxide, and hydrogen). It may be seen from the plots oftemperatures of the conductor, conduit, and opening for the conduitfilled with air, that at higher temperatures approaching 871° C., thetemperatures of the conductor, conduit, and opening begin toequilibrate, as seen for the helium filled conduit with high emissivity.

[1452]FIG. 171 illustrates temperatures of the conductor, the conduit,and the opening versus a temperature at a face of the carbon containingformation for a helium filled conduit and a low emissivity of 0.1. Theopening has a gas mixture equivalent to the second mixture describedabove having a hydrogen mole fraction of 0.6. Opening temperature 3216was linearly increased from 93° C. to 871° C. Opening temperature 3216was assumed to be the same as the temperature at the face of the carboncontaining formation. Conductor temperature 3212 and conduit temperature3214 were calculated from opening temperature 3216 using the dimensionsof the conductor, conduit, and opening, values of emissivities for theconductor, conduit, and face, and thermal conductivities for gases(helium, methane, carbon dioxide, and hydrogen). It may be seen from theplots of temperatures of the conductor, conduit, and opening for theconduit filled with helium, that at higher temperatures approaching 871°C., the temperatures of the conductor, conduit, and opening do not beginto equilibrate as seen for the high emissivity example shown in FIG.169. In addition, higher temperatures in the conductor and the conduitare needed to achieve an opening and face temperature of 871° C. Thus,increasing an emissivity of the conductor and the conduit may beadvantageous in reducing operating temperatures needed to produce adesired temperature in an oil shale formation. Such reduced operatingtemperatures may allow for the use of less expensive alloys for metallicconduits.

[1453]FIG. 172 illustrates temperatures of the conductor, the conduit,and the opening versus a temperature at a face of the carbon containingformation for an air filled conduit and a low emissivity of 0.1. Theopening has a gas mixture equivalent to the second mixture describedabove having a hydrogen mole fraction of 0.6. Opening temperature 3216was linearly increased from 93° C. to 871° C. Opening temperature 3216was assumed to be the same as the temperature at the face of the carboncontaining formation. Conductor temperature 3212 and conduit temperature3214 were calculated from opening temperature 3216 using the dimensionsof the conductor, conduit, and opening, values of emissivities for theconductor, conduit, and face, and thermal conductivities for gases (air,methane, carbon dioxide, and hydrogen). It may be seen from the plots oftemperatures of the conductor, conduit, and opening for the conduitfilled with helium, that at higher temperatures approaching 871° C., thetemperatures of the conductor, conduit, and opening do not begin toequilibrate as seen for the high emissivity example shown in FIG. 170.In addition, higher temperatures in the conductor and the conduit areneeded to achieve an opening and face temperature of 871° C. Thus,increasing an emissivity of the conductor and the conduit may beadvantageous in reducing operating temperatures needed to produce adesired temperature in an oil shale formation. Such reduced operatingtemperatures may provide for a lesser metallurgical cost associated withmaterials that require less substantial temperature resistance (e.g., alower melting point).

[1454] Calculations were also made using the first mixture of gas havinga hydrogen mole fraction of 0.2. The calculations resulted insubstantially similar results to those for a hydrogen mole fraction of0.6.

[1455]FIG. 173 depicts a retort and collection system used to conductcertain experiments. Retort vessel 3314 was a pressure vessel of 316stainless steel for holding a material to be tested. The vessel andappropriate flow lines were wrapped with a 0.0254 m by 1.83 m electricheating tape. The wrapping provided substantially uniform heatingthroughout the retort system. The temperature was controlled bymeasuring a temperature of the retort vessel with a thermocouple andaltering the electrical input to the heating tape with a proportionalcontroller to approach a desired set point. Insulation surrounded theheating tape. The vessel sat on a 0.0508 m thick insulating block. Theheating tape extended past the bottom of the stainless steel vessel tocounteract heat loss from the bottom of the vessel.

[1456] A 0.00318 m stainless steel dip tube 3312 was inserted throughmesh screen 3310 and into the small dimple on the bottom of vessel 3314.Dip tube 3312 was slotted near an end to inhibit plugging of the diptube. Mesh screen 3310 was supported along the cylindrical wall of thevessel by a small ring having a thickness of about 0.00159 m. The smallring provides a space between an end of dip tube 3312 and a bottom ofretort vessel 3314 to inhibit solids from plugging the dip tube. Athermocouple was attached to the outside of the vessel to measure atemperature of the steel cylinder. The thermocouple was protected fromdirect heat of the heater by a layer of insulation. Air-operateddiaphragm type backpressure valve 3304 was provided for tests atelevated pressures. The products at atmospheric pressure passed intoconventional glass laboratory condenser 3320. Coolant disposed in thecondenser 3320 was chilled water having a temperature of about 1.7° C.The oil vapor and steam products condensed in the flow lines of thecondenser flowed into the graduated glass collection tube. A volume ofproduced oil and water was measured visually. Non-condensable gas flowedfrom condenser 3320 through gas bulb 3316. Gas bulb 3316 has a capacityof 500 cm³. In addition, gas bulb 3316 was originally filled withhelium. The valves on the bulb were two-way valves 3317 to provide easypurging of bulb 3316 and removal of non-condensable gases for analysis.Considering a sweep efficiency of the bulb, the bulb would be expectedto contain a composite sample of the previously produced 1 to 2 litersof gas. Standard gas analysis methods were used to determine the gascomposition. The gas exiting the bulb passed into collection vessel 3318that is in water 3322 in water bath 3324. Water bath 3324 was graduatedto provide an estimate of the volume of the produced gas over a time ofthe procedure (the water level changed, thereby indicating the amount ofgas produced). Collection vessel 3318 also included an inlet valve at abottom of the collection system under water and a septum at a top of thecollection system for transfer of gas samples to an analyzer.

[1457] At location 3300 one or more gases may be injected into thesystem shown in FIG. 173 to pressurize, maintain pressure, or sweepfluids in the system. Pressure gauge 3302 may be used to monitorpressure in the system. Heating/insulating material 3306 (e.g.,insulation or a temperature control bath) may be used to regulate and/ormaintain temperatures. Controller 3308 may be used to control heating ofvessel 3314.

[1458] A final volume of gas produced is not the volume of gas collectedover water because carbon dioxide and hydrogen sulfide are soluble inwater. Analysis of the water has shown that the gas collection systemover water removes about a half of the carbon dioxide produced in atypical experiment. The concentration of carbon dioxide in water affectsa concentration of the non-soluble gases collected over water. Inaddition, the volume of gas collected over water was found to vary fromabout one-half to two-thirds of the volume of gas produced.

[1459] The system was purged with about 5 to 10 pore volumes of heliumto remove all air and pressurized to about 20 bars absolute for 24 hoursto check for pressure leaks. Heating was then started slowly, takingabout 4 days to reach 260° C. After about 8 to 12 hours at 260° C., thetemperature was raised as specified by the schedule desired for theparticular test. Readings of temperature on the inside and outside ofthe vessel were recorded frequently to assure that the controller wasworking correctly.

[1460] In one experiment, oil shale was tested in the system shown inFIG. 173. In this experiment, 270° C. was about the lowest temperatureat which oil was generated at any appreciable rate. Water productionstarted at about 100° C. and was monitored at all times during the run.Various amounts of gas were generated during the course of production.Gas production was monitored throughout the run.

[1461] Oil and water production were collected in 4 or 5 fractionsthroughout the run. These fractions were composite samples over aparticular time interval involved. The cumulative volume of oil andwater in each fraction was measured as it accrued. After each fractionwas collected, the oil was analyzed as desired. The density of the oilwas measured.

[1462] After the test, the retort was cooled, opened, and inspected forevidence of any liquid residue. A representative sample of the crushedshale loaded into the retort was taken and analyzed for oil generatingpotential by the Fischer Assay method. After the test, three samples ofspent shale in the retort were taken: one near the top, one at themiddle, and one near the bottom. These samples were tested for remainingorganic matter and elemental analysis.

[1463] Experimental data from the experiment described above was used todetermine a pressure-temperature relationship relating to the quality ofthe produced fluids. Varying the operating conditions included alteringtemperatures and pressures. Various samples of oil shale were pyrolyzedat various operating conditions. The quality of the produced fluids wasdescribed by a number of desired properties. Desired properties includedAPI gravity, an ethene to ethane ratio, an atomic carbon to atomichydrogen ratio, equivalent liquids produced (gas and liquid), liquidsproduced, percent of Fischer Assay, and percent of fluids with carbonnumbers greater than about 25. Based on data collected in theseequilibrium experiments, families of curves for several values of eachof the properties were constructed as shown in FIGS. 174-180. EQNS. 53,54, and 55 were used to describe the functional relationship of a givenvalue of a property:

P=exp[(A/T)+B],  (53)

A=a ₁*(property)³ +a ₂*(property)² +a ₃*(property)+a ₄  (54)

B=b ₁*(property)³ +b ₂*(property)² +b ₃*(property)+b ₄.  (55)

[1464] The generated curves may be used to determine a selectedtemperature and a selected pressure for producing fluids with desiredproperties.

[1465] In FIG. 174, a plot of gauge pressure versus temperature isdepicted (in FIGS. 174-180 the pressure is indicated in bars). Linesrepresenting the fraction of products with carbon numbers greater thanabout 25 were plotted. For example, when operating at a temperature of375° C. and a pressure of 4.5 bars absolute, 15% of the produced fluidhydrocarbons had a carbon number equal to or greater than 25. At lowpyrolysis temperatures and high pressures, the fraction of producedfluids with carbon numbers greater than about 25 decreases. Therefore,operating at a high pressure and a pyrolysis temperature at the lowerend of the pyrolysis temperature zone may decrease the fraction offluids with carbon numbers greater than 25 produced from oil shale.

[1466]FIG. 175 illustrates oil quality produced from an oil shaleformation as a function of pressure and temperature. Lines indicatingdifferent oil qualities, as defined by API gravity, are plotted. Forexample, the quality of the produced oil was 40° API when pressure wasmaintained at about 11.1 bars absolute and a temperature was about 375°C. Low pyrolysis temperatures and relatively high pressures may producea high API gravity oil.

[1467]FIG. 176 illustrates an ethene to ethane ratio produced from anoil shale formation as a function of pressure and temperature. Forexample, at a pressure of 21.7 bars absolute and a temperature of 375°C., the ratio of ethene to ethane is approximately 0.01. The volumeratio of ethene to ethane may predict an olefin to alkane ratio ofhydrocarbons produced during pyrolysis. Olefin content may be reduced byoperating at temperatures at a lower end of a pyrolysis temperaturerange and at a high pressure.

[1468]FIG. 177 depicts the dependence of yield of equivalent liquidsproduced from an oil shale formation as a function of temperature andpressure. Line 3340 represents the pressure-temperature combination atwhich 8.38×10⁻⁵ m³ of fluid per kilogram of oil shale (20 gallons/ton)was produced. The pressure/temperature plot results in line 3342 for theproduction of total fluids per ton of oil shale equal to 1.05×10⁻⁴ m³/kg(25 gallons/ton). Line 3344 illustrates that 1.21×10⁻⁴ m³ of fluid wasproduced from 1 kilogram of oil shale (30 gallons/ton). At a temperatureof about 325° C. and a pressure of about 14.8 bars absolute, theresulting equivalent liquids produced was 8.38×10⁻⁵ m³/kg. Astemperature of the retort increased and the pressure decreased, theyield of the equivalent liquids produced increased. Equivalent liquidsproduced is defined as the amount of liquids equivalent to the energyvalue of the produced gas and liquids.

[1469]FIG. 178 illustrates a plot of oil yield produced from treating anoil shale formation, measured as volume of liquids per ton of theformation, as a function of temperature and pressure of the retort.Temperature is illustrated in units of Celsius on the x-axis, andpressure is illustrated in units of bars absolute on the y-axis. Asshown in FIG. 178, the yield of liquid/condensable products increases astemperature of the retort increases and pressure of the retortdecreases. The lines on FIG. 178 correspond to different liquidproduction rates measured as the volume of liquids produced per weightof oil shale. The data is tabulated in TABLE 15. TABLE 15 LINE VOLUMEPRODUCED/MASS OF OIL SHALE (m³/kg) 3350 5.84 × 10⁻⁵ 3352 6.68 × 10⁻⁵3354 7.51 × 10⁻⁵ 3356 8.35 × 10⁻⁵

[1470]FIG. 179 illustrates yield of oil produced from treating an oilshale formation expressed as a percent of Fischer Assay as a function oftemperature and pressure. Temperature is illustrated in units of degreesCelsius on the x-axis, and gauge pressure is illustrated in units ofbars on the y-axis. Fischer Assay was used as a method for assessing arecovery of hydrocarbon condensate from the oil shale. In this case, amaximum recovery would be 100% of the Fischer Assay. As the temperaturedecreased and the pressure increased, the percent of Fischer Assay yielddecreased.

[1471]FIG. 180 illustrates hydrogen to carbon ratio of hydrocarboncondensate produced from an oil shale formation as a function of atemperature and pressure. Temperature is illustrated in units of degreesCelsius on the x-axis, and pressure is illustrated in units of bars onthe y-axis. As shown in FIG. 180, a hydrogen to carbon ratio ofhydrocarbon condensate produced from an oil shale formation decreases asa temperature increases and as a pressure decreases. Treating an oilshale formation at high temperatures may decrease a hydrogenconcentration of the produced hydrocarbon condensate.

[1472]FIG. 181 illustrates the effect of pressure and temperature withinan oil shale formation on a ratio of olefins to paraffins. Therelationship of the value of one of the properties (R) with temperaturehas the same functional form as the pressure-temperature relationshipspreviously discussed. In this case, the property (R) can be explicitlyexpressed as a function of pressure and temperature, as in EQNS. 56, 57,and 58.

R=exp[F(P)/T)+G(P)]  (56)

F(P)=f ₁*(P)³ +f ₂*(P)² +f ₃*(P)+f ₄  (57)

G(P)=g ₁*(P)³ +g ₂*(P)² +g ₃*(P)+g ₄  (58)

[1473] wherein R is a value of the property, T is the absolutetemperature (in Kelvin), and F(P) and G(P) are functions of pressurerepresenting the slope and intercept of a plot of R versus 1/T.

[1474] Data from experiments were compared to data from other sources.Isobars were plotted on a temperature versus olefin to paraffin ratiograph using data from a variety of sources. Data from the experimentsincluded isobars at 1 bar absolute 3360, 2.5 bars absolute 3362, 4.5bars absolute 3364, 7.9 bars absolute 3366, and 14.8 bars absolute 3368.Additional data plotted included data from a surface retort, data fromLjungstrom 3361, and data from ex situ oil shale studies conducted byLawrence Livermore Laboratories 3363. As illustrated in FIG. 181, theolefin to paraffin ratio appears to increase as the pyrolysistemperature increases. However, for a fixed temperature, the ratiodecreases rapidly with an increase in pressure. Higher pressures andlower temperatures appear to favor the lowest olefin to paraffin ratios.At a temperature of about 350° C. and a pressure of about 7.9 barsabsolute 3366, a ratio of olefins to paraffins was approximately 0.01.Pyrolyzing at reduced temperature and increased pressure may decrease anolefin to paraffin ratio. Pyrolyzing hydrocarbons for a longer period oftime, which may be accomplished by increasing pressure within thesystem, may result in a lower average molecular weight oil. In addition,production of gas may increase with pressure is increased. Anon-volatile coke may be formed in the formation.

[1475]FIG. 182 illustrates a relationship between an API gravity of ahydrocarbon condensate fluid, the partial pressure of molecular hydrogenwithin the fluid, and a temperature within an oil shale formation. Asillustrated in FIG. 182, as a partial pressure of hydrogen within thefluid increased, the API gravity generally increased. In addition, lowerpyrolysis temperatures appear to have increased the API gravity of theproduced fluids. Maintaining a partial pressure of molecular hydrogenwithin a heated portion of an oil shale formation may increase the APIgravity of the produced fluids.

[1476] In FIG. 183, a quantity of oil liquids produced in m³ of liquidsper kg of oil shale formation is plotted versus a partial pressure ofH₂. Also illustrated in FIG. 183 are various curves for pyrolysisoccurring at different temperatures. At higher pyrolysis temperatures,production of oil liquids was higher than at the lower pyrolysistemperatures. In addition, high pressures tended to decrease thequantity of oil liquids produced from an oil shale containing formation.Operating an in situ conversion process at low pressures and hightemperatures may produce a higher quantity of oil liquids than operatingat low temperatures and high pressures.

[1477] As illustrated in FIG. 184, an ethene to ethane ratio in theproduced gas increased with increasing temperature. In addition,application of pressure decreased the ethene to ethane ratiosignificantly. As illustrated in FIG. 184, lower temperatures and higherpressures decreased the ethene to ethane ratio. The ethene to ethaneratio is indicative of the olefin to paraffin ratio in the condensedhydrocarbons.

[1478]FIG. 185 illustrates an atomic hydrogen to atomic carbon ratio inthe hydrocarbon liquids. In general, lower temperatures and higherpressures increased the atomic hydrogen to atomic carbon ratio of theproduced hydrocarbon liquids.

[1479] A small-scale field experiment of an in situ conversion processin oil shale was conducted. An objective of this test was tosubstantiate laboratory experiments that produced high quality crudeutilizing the in situ retort process.

[1480] As illustrated in FIG. 186, the field experiment consisted of asingle unconfined hexagonal seven spot pattern on eight foot spacing.Six heat injection wells 3600, drilled to a depth of 40 m, contained 17m long heating elements that injected thermal energy into the formationfrom 21 m to 39 m. A single producer well 3602 in the center of thepattern captured the liquids and vapors from the in situ retort. Threeobservation wells 3603 inside the pattern and one outside the patternrecorded formation temperatures and pressures. Six dewatering wells 3604surrounded the pattern on 6 m spacing and were completed in an activeaquifer below the heated interval (from 44 m to 61 m). FIG. 187 depictsa cross-sectional representation of the field experiment. Producer well3602 includes pump 3614. Lower portion 3612 of producer well 3602 waspacked with gravel. Upper portion 3610 of producer well 3602 wascemented. Heater wells 3600 were located a distance of approximately 2.4m from producer well 3602. A heating element was located within theheater well and the heater well was cemented in place. Dewatering wells3604 were located approximately 4.0 m from heater wells 3600. Coringwell 3606 was located approximately 0.5 m from heater wells 3600.

[1481] Produced oil, gas, and water were sampled and analyzed throughoutthe life of the experiment. Surface and subsurface pressures andtemperatures and energy injection data were captured electronically andsaved for future evaluation. The composite oil produced from the testhad a 36° API gravity with a low olefin content of 1.1 weight % and aparaffin content of 66 weight %. The composite oil also included asulfur content of 0.4 weight %. This condensate-like crude confirmed thequality predicted from the laboratory experiments. The composition ofthe gas changed throughout the test. The gas was high in hydrogen(average approximately 25 mol %) and CO₂ (average approximately 15 mol%), as expected.

[1482] Evaluation of the post heat core indicates that the oil shalezone was thoroughly retorted except for the top and bottom 1 m to 1.2 m.Oil recovery efficiency was shown to be in the 75% to 80% range. Someretorting also occurred at least two feet outside of the pattern. Duringthe in situ conversion process experiment, the formation pressures weremonitored with pressure monitoring wells. The pressure increased to ahighest pressure at 9.4 bars absolute and then slowly declined. The highoil quality was produced at the highest pressure and temperatures below350° C. The pressure was allowed to decrease to atmospheric astemperatures increased above 370° C. As predicted, the oil compositionunder these conditions was shown to be of lower API gravity, highermolecular weight, greater carbon numbers in carbon number distribution,higher olefin content, and higher sulfur and nitrogen contents.

[1483]FIG. 188 illustrates a plot of the maximum temperatures withineach of three innermost observation wells 3603 (see FIG. 186) versustime. The temperature profiles were very similar for the threeobservation wells. Heat was provided to the oil shale formation for 216days. As illustrated in FIG. 188, the temperature at the observer wellsincreased steadily until the heat was turned off.

[1484]FIG. 189 illustrates a plot of hydrocarbon liquids production, inbarrels per day, for the same in situ experiment. In this figure, theline marked as “Separator Oil” indicates the hydrocarbon liquids thatwere produced after the produced fluids were cooled to ambientconditions and separated. In this figure the line marked as “Oil &C5+Gas Liquids” includes the hydrocarbon liquids produced after theproduced fluids were cooled to ambient conditions and separated and, inaddition, the assessed C₅ and heavier compounds that were flared. Thetotal liquid hydrocarbons produced to a stock tank during the experimentwas 194 barrels. The total equivalent liquid hydrocarbons produced(including the C₅ and heavier compounds) was 250 barrels. As indicatedin FIG. 189, the heat was turned off at day 216, however, somehydrocarbons continued to be produced thereafter.

[1485]FIG. 190 illustrates a plot of production of hydrocarbon liquids(in barrels per day), gas (in MCF per day), and water (in barrels perday), versus heat energy injected (in megawatt-hours), during the samein situ experiment. As shown in FIG. 190, the heat was turned off afterabout 440 megawatt-hours of energy had been injected.

[1486] As illustrated in FIG. 191, pressure within the oil shalematerial showed some variations initially at different depths, however,over time these variations equalized. FIG. 191 depicts the gauge fluidpressure in observation well 3603 versus time measured in days at aradial distance of 2.1 m from production well 3602, shown in FIG. 186.The fluid pressures were monitored at depths of 24 m and 33 m. Thesedepths corresponded to a richness within the oil shale material of8.3×10⁻⁵ m³ of oil/kg of oil shale at 24 m and 1.7×10⁻⁴ m³ of oil/kg ofoil shale at 33 m. The higher pressures initially observed at 33 m maybe the result of a higher generation of fluids due to the richness ofthe oil shale material at that depth. In addition, at lower depths alithostatic pressure may be higher, causing the oil shale material at 33m to fracture at higher pressure than at 24 m. During the course of theexperiment, pressures within the oil shale formation equalized. Theequalization of the pressure may have resulted from fractures formingwithin the oil shale formation.

[1487]FIG. 192 is a plot of API gravity versus time measured in days. Asillustrated in FIG. 192, the API gravity was relatively high (i.e.,hovering around 40° until about 140 days). The API gravity, although itstill varied, decreased steadily thereafter. Prior to 110 days, thepressure measured at shallower depths was increasing, and after 10 days,it began to decrease significantly. At about 140 days, the pressure atthe deeper depths began to decrease. At about 140 days, the temperatureas measured at the observation wells increased above about 370° C.

[1488] In FIG. 193 average carbon numbers of the produced fluid areplotted versus time measured in days. At approximately 140 days, theaverage carbon number of the produced fluids increased. Thisapproximately corresponded to the temperature rise and the drop inpressure illustrated in FIG. 188 and FIG. 191, respectively. Inaddition, as shown in FIG. 194, the density of the produced hydrocarbonliquids, in grams per cc, increased at approximately 140 days. Thequality of the produced hydrocarbon liquids, as demonstrated in FIG.192, FIG. 193, and FIG. 194, decreased as the temperature increased andthe pressure decreased.

[1489]FIG. 195 depicts a plot of the weight percent of specific carbonnumbers of hydrocarbons within the produced hydrocarbon liquids. Thevarious curves represent different times at which the liquids wereproduced. The carbon number distribution of the produced hydrocarbonliquids for the first 136 days exhibited a relatively narrow carbonnumber distribution, with a low weight percent of carbon numbers above16. The carbon number distribution of the produced hydrocarbon liquidsbecomes progressively broader as time progresses after 136 days (e.g.,from 199 days to 206 days to 231 days). As the temperature continued toincrease and the pressure had decreased towards one atmosphere absolute,the product quality steadily deteriorated.

[1490]FIG. 196 illustrates a plot of the weight percent of specificcarbon numbers of hydrocarbons within the produced hydrocarbon liquids.Curve 3620 represents the carbon distribution for the composite mixtureof hydrocarbon liquids over the entire in situ conversion process(“ICP”) field experiment. For comparison, a plot of the carbon numberdistribution for hydrocarbon liquids produced from a surface retort ofthe same Green River oil shale is also depicted as curve 3622. In thesurface retort, oil shale was mined, placed in a vessel, and rapidlyheated at atmospheric pressure to a high temperature in excess of 500°C. As illustrated in FIG. 196, a carbon number distribution of themajority of the hydrocarbon liquids produced from the ICP fieldexperiment was within a range of 8 to 15. The peak carbon number fromproduction of oil during the ICP field experiment was about 13. Incontrast, the surface retort 3622 has a relatively flat carbon numberdistribution with a substantial amount of carbon numbers greater than25. In addition, the acid number of oil produced from the ICP fieldexperiment was 0.14 mg/gram KOH.

[1491] During the ICP experiment, the formation pressures were monitoredwith pressure monitoring wells. The pressure increased to a highestpressure at 9.3 bars absolute and then slowly declined. The high oilquality was produced at the highest pressures and temperatures below350° C. The pressure was allowed to decrease to atmospheric astemperatures increased above 370° C. As predicted, the oil compositionunder these conditions was shown to be of lower API gravity, highermolecular weight, greater carbon numbers in the carbon numberdistribution, higher olefin content, and higher sulfur and nitrogencontents.

[1492] Experimental data from studies conducted by Lawrence LivermoreNational Laboratories (LLNL) was plotted along with laboratory data fromthe in situ conversion process (ICP) for an oil shale formation atatmospheric pressure in FIG. 197. The oil recovery as a percent ofFischer Assay was plotted against a log of the heating rate. Data fromLLNL 3642 included data derived from pyrolyzing powdered oil shale atatmospheric pressure and in a range from about 2 bars absolute to about2.5 bars absolute. As illustrated in FIG. 197, data from LLNL 3642 has alinear trend. Data from ICP 3640 demonstrates that oil recovery, asmeasured by Fischer Assay, was much higher for ICP than data from LLNL3642 would suggest. FIG. 197 shows that oil recovery from oil shale mayincrease along an S-curve, instead of linearly, as a function of heatingrate.

[1493] Results from the oil shale field experiment (e.g., measuredpressures, temperatures, produced fluid quantities and compositions,etc.) were input into a numerical simulation model to assess formationfluid transport mechanisms. FIG. 198 shows the results from the computersimulation. In FIG. 198, oil production 3670 in stock tank barrels/daywas plotted versus time. Area 3674 represents the liquid hydrocarbons inthe formation at reservoir conditions that were measured in the fieldexperiment. FIG. 198 indicates that more than 90% of the hydrocarbons inthe formation were vapors. Based on these results and the fact that thewells in the field test produced mostly vapors (until such vapors werecooled, at which point hydrocarbon liquids were produced), it isbelieved that hydrocarbons in the formation move through the formationprimarily as vapors when heated.

[1494]FIG. 200 depicts a cross-sectional representation of an in situexperimental field test system. As shown in FIG. 200, the experimentalfield test system included coal formation 3802 within the ground andgrout wall 3800. Coal formation 3802 dipped at an angle of approximately36° with a thickness of approximately 4.9 m. FIG. 199 illustrates alocation of heat sources 3804 a, 3804 b, 3804 c, production wells 3806a, 3806 b, and temperature observation wells 3808 a, 3808 b, 3808 c,3808 d used for the experimental field test system. The three heatsources were disposed in a triangular configuration. Production well3806 a was located proximate a center of the heat source pattern andequidistant from each of the heat sources. Second production well 3806 bwas located outside the heat source pattern and spaced equidistant fromthe two closest heat sources. Grout wall 3800 was formed around the heatsource pattern and the production wells. The grout wall was formed of 24pillars. Grout wall 3800 inhibited an influx of water into the portionduring the in situ experiment. In addition, grout wall 3800 inhibitedloss of generated hydrocarbon fluids to an unheated portion of theformation.

[1495] Temperatures were measured at various times during the experimentat each of four temperature observation wells 3808 a, 3808 b, 3808 c,3808 d located within and outside of the heat source pattern as shown inFIG. 199. The temperatures measured at each of the temperatureobservation wells are displayed in FIG. 201 as a function of time.Temperatures at observation wells 3808 a (3820), 3808 b (3822), and 3808c (3824) were relatively close to each other. A temperature attemperature observation well 3808 d (3826) was significantly colder.This temperature observation well was located outside of the heater welltriangle illustrated in FIG. 199. This data demonstrates that in zoneswhere there was little superposition of heat, temperatures weresignificantly lower. FIG. 202 illustrates temperature profiles measuredat heat sources 3804 a (3830), 3804 b (3832), and 3804 c (3834). Thetemperature profiles were relatively uniform at the heat sources.

[1496] Synthesis gas was also produced in an in situ experiment from theportion of the coal formation shown in FIG. 200 and FIG. 199. In thisexperiment, heater wells were used to inject fluids into the formation.FIG. 203 is a plot of weight of volatiles (condensable anduncondensable) in kilograms as a function of cumulative energy contentof product in kilowatt hours from the in situ experimental field test.The figure illustrates the quantity and energy content of pyrolysisfluids and synthesis gas produced from the formation.

[1497]FIG. 204 is a plot of the volume of oil equivalent produced (m³)as a function of energy input into the coal formation (kW·h) from theexperimental field test. The volume of oil equivalent in cubic meterswas determined by converting the energy content of the volume ofproduced oil plus gas to a volume of oil with the same energy content.

[1498] The start of synthesis gas production, indicated by arrow 3912,was at an energy input of approximately 77,000 kW·h. The average coaltemperature in the pyrolysis region had been raised to 620° C. Becausethe average slope of the curve in FIG. 204 in the pyrolysis region isgreater than the average slope of the curve in the synthesis gas region,FIG. 204 illustrates that the amount of useable energy contained in theproduced synthesis gas is less than that contained in the pyrolysisfluids. Therefore, synthesis gas production is less energy efficientthan pyrolysis. There are two reasons for this result. First, the two H₂molecules produced in the synthesis gas reaction have a lower energycontent than low carbon number hydrocarbons produced in pyrolysis.Second, endothermic synthesis gas reactions consume energy.

[1499]FIG. 205 is a plot of the total synthesis gas production (m³/min)from the coal formation versus the total water inflow (kg/h) due toinjection into the formation from the experimental field test resultsfacility. Synthesis gas may be generated in a formation at a synthesisgas generating temperature before the injection of water or steam due tothe presence of natural water inflow into hot coal formation. Naturalwater may come from below the formation.

[1500] From FIG. 205, the maximum natural water inflow is approximately5 kg/h as indicated by arrow 3920. Arrows 3922, 3924, and 3926 representinjected water rates of about 2.7 kg/h, 5.4 kg/h, and 11 kg/h,respectively, into central well 3806 a of FIG. 199. Production ofsynthesis gas is at heater wells 3804 a, 3804 b, and 3804 c. FIG. 205shows that the synthesis gas production per unit volume of waterinjected decreases at arrow 3922 at approximately 2.7 kg/h of injectedwater or 7.7 kg/h of total water inflow. The reason for the decrease maybe that steam is flowing too fast through the coal seam to allow thereactions to approach equilibrium conditions.

[1501]FIG. 206 illustrates production rate of synthesis gas (m³/min) asa function of steam injection rate (kg/h) in a coal formation. Data 3930for a first run corresponds to injection at producer well 3806 a in FIG.199 and production of synthesis gas at heater wells 3804 a, 3804 b, and3804 c. Data 3932 for a second run corresponds to injection of steam atheater well 3804 c and production of additional gas at a production well3806 a. Data 3930 for the first run corresponds to the data shown inFIG. 205. As shown in FIG. 206, the injected water is in reactionequilibrium with the formation to about 2.7 kg/h of injected water. Thesecond run results in substantially the same amount of additionalsynthesis gas produced, shown by data 3932, as the first run to about1.2 kg/h of injected steam. At about 1.2 kg/h, data 3930 starts todeviate from equilibrium conditions because the residence time isinsufficient for the additional water to react with the coal. Astemperature is increased, a greater amount of additional synthesis gasis produced for a given injected water rate. The reason is that athigher temperatures the reaction rate and conversion of water intosynthesis gas increases.

[1502]FIG. 207 is a plot that illustrates the effect of methaneinjection into a heated coal formation in the experimental field test(all of the units in FIGS. 207-210 are in m³ per hour). FIG. 207demonstrates hydrocarbons added to the synthesis gas producing fluid arecracked within the formation. FIG. 199 illustrates the layout of theheater and production wells at the field test facility. Methane wasinjected into production wells 3806 a and 3806 b and fluid was producedfrom heater wells 3804 a, 3804 b, and 3804 c. The average temperaturesat various wells were as follows: 3804 a (746° C.), 3804 b (746° C.),3804 c (767° C.), 3808 a (592° C.), 3808 b (573° C.), 3808 c (606° C.),and 3806 a (769° C.). When the methane contacted the formation, aportion of the methane cracked within the formation to produce H₂ andcoke. FIG. 207 shows that as the methane injection rate increased, theproduction of H₂ 3940 increased. This indicated that methane wascracking to form H₂. Methane production 3942 also increased, whichindicates that not all of the injected methane is cracked. The measuredcompositions of ethane, ethene, propane, and butane were negligible.

[1503]FIG. 208 is a plot that illustrates the effect of ethane injectioninto a heated coal formation in the experimental field test. Ethane wasinjected into production wells 3806 a and 3806 b and fluid was producedfrom heater wells 3804 a, 3804 b, and 3804 c in FIG. 199. The averagetemperatures at various wells were as follows: 3804 a (742° C.), 3804 b(750° C.), 3804 c (744° C.), 3808 a (611° C.), 3808 b (595° C.), 3808 c(626° C.), and 3806 a (818° C.). When ethane contacted the formation, itcracked to produce H₂, methane, ethene, and coke. FIG. 208 shows that asthe ethane injection rate increased, the production of H₂ 3950, methane3952, ethane 3954, and ethene 3956 increased. This indicates that ethaneis cracking to form H₂ and low molecular weight hydrocarbons. Theproduction rate of higher carbon number products (i.e., propane andpropylene) were unaffected by the injection of ethane.

[1504]FIG. 209 is a plot that illustrates the effect of propaneinjection into a heated coal formation in the experimental field test.Propane was injected into production wells 3806 a and 3806 b and fluidwas produced from heater wells 3804 a, 3804 b, and 3804 c. The averagetemperatures at various wells were as follows: 3804 a (737° C.), 3804 b(753° C.), 3804 c (726° C.), 3808 a (589° C.), 3808 b (573° C.), 3808 c(606° C.), and 3806 a (769° C.). When propane contacted the formation,it cracked to produce H₂, methane, ethane, ethene, propylene, and coke.FIG. 209 shows that as the propane injection rate increased, theproduction of H₂ 3960, methane 3962, ethane 3964, ethene 3966, propane3968, and propylene 3969 increased. This indicates that propane iscracking to form H₂ and lower molecular weight components.

[1505]FIG. 210 is a plot that illustrates the effect of butane injectioninto a heated coal formation in the experimental field test. Butane wasinjected into production wells 3806 a and 3806 b and fluid was producedfrom heater wells 3804 a, 3804 b, and 3804 c. The average temperature atvarious wells were as follows: 3804 a (772° C.), 3804 b (764° C.), 3804c (753° C.), 3808 a (650° C.), 3808 b (591° C.), 3808 c (624° C.), and3806 a (830° C.). When butane contacted the formation, it cracked toproduce H₂, methane, ethane, ethene, propane, propylene, and coke. FIG.210 shows that as the butane injection rate increased, the production ofH₂ 3970, methane 3972, ethane 3974, ethene 3976, propane 3978, andpropylene 3979 increased. This indicates that butane is cracking to formH₂ and lower molecular weight components.

[1506]FIG. 211 is a plot of the composition of gas (in mole percent)produced from the heated coal formation versus time in days at theexperimental field test. The species compositions included methane 3980,H₂ 3982, carbon dioxide 3984, hydrogen sulfide 3986, and carbon monoxide3988. FIG. 211 shows a dramatic increase in H₂ concentration after about150 days, or when synthesis gas production began.

[1507]FIG. 212 is a plot of synthesis gas conversion versus time forsynthesis gas generation runs in the experimental field test performedon separate days. The temperature of the formation was about 600° C. Thedata demonstrates initial uncertainty in measurements in the oil/waterseparator. Synthesis gas conversion consistently approached a conversionof between about 40% and 50% after about 2 hours of synthesis gasproducing fluid injection.

[1508] TABLE 16 shows a composition of synthesis gas produced during arun of the in situ coal field experiment. TABLE 16 Component Mol % Wt %Methane 12.263 12.197 Ethane 0.281 0.525 Ethene 0.184 0.320 Acetylene0.000 0.000 Propane 0.017 0.046 Propylene 0.026 0.067 Propadiene 0.0010.004 Isobutane 0.001 0.004 n-Butane 0.000 0.001 1-Butene 0.001 0.003Isobutene 0.000 0.000 cis-2-Butene 0.005 0.018 trans-2-Butene 0.0010.003 1,3-Butadiene 0.001 0.005 Isopentane 0.001 0.002 n-Pentane 0.0000.002 Pentene-1 0.000 0.000 T-2-Pentene 0.000 0.000 2-Methyl-2-Butene0.000 0.000 C-2-Pentene 0.000 0.000 Hexanes 0.081 0.433 H₂ 51.247 6.405Carbon monoxide 11.556 20.067 Carbon dioxide 17.520 47.799 Nitrogen5.782 10.041 Oxygen 0.955 1.895 Hydrogen sulfide 0.077 0.163 Total100.000 100.000

[1509] The experiment was performed in batch oxidation mode at about620° C. The presence of nitrogen and oxygen is due to contamination ofthe sample with air. The mole percent of H₂, carbon monoxide, and carbondioxide, neglecting the composition of all other species, may bedetermined for the above data. For example, mole percent of H₂, carbonmonoxide, and carbon dioxide may be increased proportionally such thatthe mole percentages of the three components equals approximately 100%.The mole percent of H₂, carbon monoxide, and carbon dioxide, neglectingthe composition of all other species, were 63.8%, 14.4%, and 21.8%,respectively. The methane is believed to come primarily from thepyrolysis region outside the triangle of heaters. These values are insubstantial agreement with the equilibrium values shown in FIG. 213.

[1510]FIG. 213 is a plot of calculated equilibrium gas dry molefractions for a coal reaction with water. Methane reactions are notincluded. The fractions are representative of a synthesis gas producedfrom a hydrocarbon containing formation and has been passed through acondenser to remove water from the produced gas. Equilibrium gas drymole fractions are shown in FIG. 213 for H₂ 4000, carbon monoxide 4002,and carbon dioxide 4004 as a function of temperature at a pressure of 2bars absolute. Liquid production from a formation substantially stops attemperatures of about 390° C. Gas produced at about 390° C. includesabout 67% H₂ and about 33% carbon dioxide. Carbon monoxide is present innegligible quantities below about 410° C. At temperatures of about 500°C., however, carbon monoxide is present in the produced gas inmeasurable quantities. For example, at 500° C., about 66.5% H₂, about32% carbon dioxide, and about 2.5% carbon monoxide are present. At 700°C., the produced gas includes about 57.5% H₂, about 15.5% carbondioxide, and about 27% carbon monoxide.

[1511]FIG. 214 is a plot of calculated equilibrium wet mole fractionsfor a coal reaction with water. Methane reactions are not included.Equilibrium wet mole fractions are shown for water 4006, H₂ 4008, carbonmonoxide 4010, and carbon dioxide 4012 as a function of temperature at apressure of 2 bars absolute. At 390° C., the produced gas includes about89% water, about 7% H₂, and about 4% carbon dioxide. At 500° C., theproduced gas includes about 66% water, about 22% H₂, about 11% carbondioxide, and about 1% carbon monoxide. At 700° C., the produced gasincludes about 18% water, about 47.5% H₂, about 12% carbon dioxide, andabout 22.5% carbon monoxide.

[1512]FIG. 213 and FIG. 214 illustrate that at the lower end of thetemperature range at which synthesis gas may be produced (i.e., about400° C.), equilibrium gas phase fractions may not favor production of H₂within and from a formation. As temperature increases, the equilibriumgas phase fractions increasingly favor the production of H₂. Forexample, as shown in FIG. 214, the gas phase equilibrium wet molefraction of H₂ increases from about 9% at 400° C. to about 39% at 610°C. and reaches 50% at about 800° C. FIG. 213 and FIG. 214 furtherillustrate that at temperatures greater than about 660° C., equilibriumgas phase fractions tend to favor production of carbon monoxide overcarbon dioxide.

[1513]FIG. 213 and FIG. 214 illustrate that as the temperature increasesfrom between about 400° C. to about 1000° C., the H₂ to carbon monoxideratio of produced synthesis gas may continuously decrease throughoutthis range. For example, as shown in FIG. 214, the equilibrium gas phaseH₂ to carbon monoxide ratio at 500° C., 660° C., and 1000° C. is about22:1, about 3:1, and about 1:1, respectively. FIG. 214 also indicatesthat produced synthesis gas at lower temperatures may have a largerquantity of water and carbon dioxide than at higher temperatures. As thetemperature increases, the overall percentage of carbon monoxide andhydrogen within the synthesis gas may increase.

[1514] Experimental adsorption data has demonstrated that carbon dioxidemay be stored in coal that has been pyrolyzed. FIG. 215 is a plot of thecumulative adsorbed methane and carbon dioxide in cubic meters permetric ton versus pressure in bars absolute at 25° C. on coal. The coalsample is sub-bituminous coal from Gillette, Wyo. Data sets 4402, 4403,4404, and 4405 are for carbon dioxide adsorption on a post treatmentcoal sample that has been pyrolyzed and has undergone synthesis gasgeneration. Data set 4406 is for adsorption on an unpyrolyzed coalsample from the same formation. Data set 4401 is adsorption of methaneat 25° C. Data sets 4402, 4403, 4404, and 4405 are adsorption of carbondioxide at 25° C., 50° C., 100° C., and 150° C., respectively. Data set4406 is adsorption of carbon dioxide at 25° C. on the unpyrolyzed coalsample. FIG. 215 shows that carbon dioxide at temperatures between 25°C. and 100° C. is more strongly adsorbed than methane at 25° C. in thepyrolyzed coal. FIG. 215 demonstrates that a carbon dioxide streampassed through post treatment coal tends to displace methane from thepost treatment coal.

[1515] Computer simulations have demonstrated that carbon dioxide may besequestered in both a deep coal formation and a post treatment coalformation. The Comet2™ Simulator (Advanced Resources International,Houston, Tex.) determined the amount of carbon dioxide that could besequestered in a San Juan Basin type deep coal formation and a posttreatment coal formation. The simulator also determined the amount ofmethane produced from the San Juan Basin type deep coal formation due tocarbon dioxide injection. The model employed for both the deep coalformation and the post treatment coal formation was a 1.3 km² area, witha repeating 5 spot well pattern. The 5 spot well pattern included fourinjection wells arranged in a square and one production well at thecenter of the square. The properties of the San Juan Basin and the posttreatment coal formations are shown in TABLE 17. Additional details ofsimulations of carbon dioxide sequestration in deep coal formations andcomparisons with field test results may be found in Pilot TestDemonstrates How Carbon Dioxide Enhances Coal Bed Methane Recovery,Lanny Schoeling and Michael McGovern, Petroleum Technology Digest,September 2000, p. 14-15. TABLE 17 Post treatment Deep Coal coalformation Formation (San (Post pyrolysis Juan Basin) process) CoalThickness (m) 9 9 Coal Depth (m) 990 460 Initial Pressure 114 2 (barsabs.) Initial Temperature 25° C. 25° C. Permeability (md) 5.5 (horiz.),10,000 (horiz.), 0 (vertical) 0 (vertical) Cleat porosity 0.2% 40%

[1516] The simulation model accounts for the matrix and dual porositynature of coal and post treatment coal. For example, coal and posttreatment coal are composed of matrix blocks. The spaces between theblocks are called “cleats.” Cleat porosity is a measure of availablespace for flow of fluids in the formation. The relative permeabilitiesof gases and water within the cleats required for the simulation werederived from field data from the San Juan coal. The same values forrelative permeabilities were used in the post treatment coal formationsimulations. Carbon dioxide and methane were assumed to have the samerelative permeability.

[1517] The cleat system of the deep coal formation was modeled asinitially saturated with water. Relative permeability data for carbondioxide and water demonstrate that high water saturation inhibitsabsorption of carbon dioxide within cleats. Therefore, water is removedfrom the formation before injecting carbon dioxide into the formation.

[1518] In addition, the gases within the cleats may adsorb in the coalmatrix. The matrix porosity is a measure of the space available forfluids to adsorb in the matrix. The matrix porosity and surface areawere taken into account with experimental mass transfer and isothermadsorption data for coal and post treatment coal. Therefore, it was notnecessary to specify a value of the matrix porosity and surface area inthe model. The pressure-volume-temperature (PVT) properties andviscosity required for the model were taken from literature data for thepure component gases.

[1519] The preferential adsorption of carbon dioxide over methane onpost treatment coal was incorporated into the model based onexperimental adsorption data. For example, FIG. 215 demonstrates thatcarbon dioxide has a significantly higher cumulative adsorption thanmethane over an entire range of pressures at a specified temperature.Once the carbon dioxide enters in the cleat system, methane diffuses outof and desorbs off the matrix. Similarly, carbon dioxide diffuses intoand adsorbs onto the matrix. In addition, FIG. 215 also shows carbondioxide may have a higher cumulative adsorption on a pyrolyzed coalsample than an unpyrolyzed coal sample.

[1520] The simulation modeled a sequestration process over a time periodof about 3700 days for the deep coal formation model. Removal of thewater in the coal formation was simulated by production from five wells.The production rate of water was about 40 m³/day for about the first 370days. The production rate of water decreased significantly after thefirst 370 days. It continued to decrease through the remainder of thesimulation run to about zero at the end. Carbon dioxide injection wasstarted at approximately 370 days at a flow rate of about 113,000standard (in this context “standard” means 1 atmosphere pressure and15.5° C.) m³/day. The injection rate of carbon dioxide was doubled toabout 226,000 standard m³/day at approximately 1440 days. The injectionrate remained at about 226,000 standard m³/day until the end of thesimulation run.

[1521]FIG. 216 illustrates the pressure at the wellhead of the injectionwells as a function of time during the simulation. The pressuredecreased from about 114 bars absolute to about 19 bars absolute overthe first 370 days. The decrease in the pressure was due to removal ofwater from the coal formation. Pressure then started to increasesubstantially as carbon dioxide injection started at 370 days. Thepressure reached a maximum of about 98 bars absolute. The pressure thenbegan to gradually decrease after 480 days. At about 1440 days, thepressure increased again to about 98 bars absolute due to the increasein the carbon dioxide injection rate. The pressure gradually increaseduntil about 3640 days. The pressure jumped at about 3640 days becausethe production well was closed off.

[1522]FIG. 217 illustrates the production rate of carbon dioxide 5060and methane 5070 as a function of time in the simulation. FIG. 217 showsthat carbon dioxide was produced at a rate between about 0-10,000 m³/dayduring approximately the first 2400 days. The production rate of carbondioxide was significantly below the injection rate. Therefore, thesimulation predicts that most of the injected carbon dioxide is beingsequestered in the coal formation. However, at about 2400 days, theproduction rate of carbon dioxide started to rise significantly due toonset of saturation of the coal formation.

[1523] In addition, FIG. 217 shows that methane was desorbing as carbondioxide was adsorbing in the coal formation. Between about 370-2400days, the methane production rate 5070 increased from about 60,000 toabout 115,000 standard m³/day. The increase in the methane productionrate between about 1440-2400 days was caused by the increase in carbondioxide injection rate at about 1440 days. The production rate ofmethane started to decrease after about 2400 days. This was due to thesaturation of the coal formation. The simulation predicted a 50%breakthrough at about 2700 days. “Breakthrough” is defined as the ratioof the flow rate of carbon dioxide to the total flow rate of the totalproduced gas times 100%. In addition, the simulation predicted about a90% breakthrough at about 3600 days.

[1524]FIG. 218 illustrates cumulative methane produced 5090 and thecumulative net carbon dioxide injected 5080 as a function of time duringthe simulation. The cumulative net carbon dioxide injected is the totalcarbon dioxide produced subtracted from the total carbon dioxideinjected. FIG. 218 shows that by the end of the simulated injection,about twice as much carbon dioxide was stored as methane produced. Inaddition, the methane production was about 0.24 billion standard m³ at50% carbon dioxide breakthrough. In addition, the carbon dioxidesequestration was about 0.39 billion standard m³ at 50% carbon dioxidebreakthrough. The methane production was about 0.26 billion standard m³at 90% carbon dioxide breakthrough. In addition, the carbon dioxidesequestration was about 0.46 billion standard m³ at 90% carbon dioxidebreakthrough.

[1525] TABLE 17 shows that the permeability and porosity of thesimulation in the post treatment coal formation were both significantlyhigher than in the deep coal formation prior to treatment. In addition,the initial pressure was much lower. The depth of the post treatmentcoal formation was shallower than the deep coal bed methane formation.The same relative permeability data and PVT data used for the deep coalformation were used for the coal formation simulation. The initial watersaturation for the post treatment coal formation was set at 70%. Waterwas present because it is used to cool the hot spent coal formation to25° C. The amount of methane initially stored in the post treatment coalis very low.

[1526] The simulation modeled a sequestration process over a time periodof about 3800 days for the post treatment coal formation model. Thesimulation modeled removal of water from the post treatment coalformation with production from five wells. During about the first 200days, the production rate of water was about 680,000 standard m³/day.From about 200-3300 days, the water production rate was between about210,000 to about 480,000 standard m³/day. Production rate of water wasnegligible after about 3300 days. Carbon dioxide injection was startedat approximately 370 days at a flow rate of about 113,000 standardm³/day. The injection rate of carbon dioxide was increased to about226,000 standard m³/day at approximately 1440 days. The injection rateremained at 226,000 standard m³/day until the end of the simulatedinjection.

[1527]FIG. 219 illustrates the pressure at the wellhead of the injectionwells as a function of time during the simulation of the post treatmentcoal formation model. The pressure was relatively constant up to about370 days. The pressure increased through most of the rest of thesimulation run up to about 36 bars absolute. The pressure rose steeplystarting at about 3300 days because the production well was closed off.

[1528]FIG. 220 illustrates the production rate of carbon dioxide as afunction of time in the simulation of the post treatment coal formationmodel. FIG. 220 shows that the production rate of carbon dioxide wasalmost negligible during approximately the first 2200 days. Therefore,the simulation predicts that nearly all of the injected carbon dioxideis being sequestered in the post treatment coal formation. However, atabout 2240 days, the produced carbon dioxide began to increase. Theproduction rate of carbon dioxide started to rise significantly due toonset of saturation of the post treatment coal formation.

[1529]FIG. 221 illustrates cumulative net carbon dioxide injected as afunction of time during the simulation in the post treatment coalformation model. The cumulative net carbon dioxide injected is the totalcarbon dioxide produced subtracted from the total carbon dioxideinjected. FIG. 221 shows that the simulation predicts a potential netsequestration of carbon dioxide of 0.56 Bm³. This value is greater thanthe value of 0.46 Bm³ at 90% carbon dioxide breakthrough in the deepcoal formation. However, comparison of FIG. 216 with FIG. 219 shows thatsequestration occurs at much lower pressures in the post treatment coalformation model. Therefore, less compression energy was required forsequestration in the post treatment coal formation.

[1530] The simulations show that large amounts of carbon dioxide may besequestered in both deep coal formations and in post treatment coalformations that have been cooled. Carbon dioxide may be sequestered inthe post treatment coal formation, in coal formations that have not beenpyrolyzed, and/or in both types of formations.

Further Improvements

[1531] Formation fluid produced from an oil shale formation duringtreatment may include a mixture of different components. To increase theeconomic value of products generated from the formation, formation fluidmay be treated using a variety of treatment processes. Processesutilized to treat formation fluid may include distillation (e.g.,atmospheric distillation, fractional distillation, and/or vacuumdistillation), condensation (e.g., fractional), cracking (e.g., thermalcracking, catalytic cracking, fluid catalytic cracking, hydrocracking,residual hydrocracking, and/or steam cracking), reforming (e.g., thermalreforming, catalytic reforming, and/or hydrogen steam reforming),hydrogenation, coking, solvent extraction, solvent dewaxing,polymerization (e.g., catalytic polymerization and/or catalyticisomerization), visbreaking, alkylation, isomerization, deasphalting,hydrodesulfurization, catalytic dewaxing, desalting, extraction (e.g.,of phenols, other aromatic compounds, etc.), and/or stripping.

[1532] Formation fluids may undergo treatment processes in a first insitu treatment area as the formation fluid is generated and produced, ina second in situ treatment area where a specific treatment processoccurs, and/or in surface treatment units. A “surface treatment unit” isa unit used to treat at least a portion of formation fluid at thesurface. Surface treatment units may include, but are not limited to,reactors (e.g., hydrotreating units, cracking units, ammonia generatingunits, fertilizer generating units, and/or oxidizing units), separatingunits (e.g., air separating units, liquid-liquid extraction units,adsorption units, absorbers, ammonia recovery and/or generating units,vapor/liquid separating units, distillation columns, reactivedistillation columns, and/or condensing units), reboiling units, heatexchangers, pumps, pipes, storage units, and/or energy producing units(e.g., fuel cells and/or gas turbines). Multiple surface treatment unitsused in series, in parallel, and/or in a combination of series andparallel are referred to as a surface facility configuration. Surfacefacility configurations may vary dramatically due to a composition offormation fluid as well as the products being generated.

[1533] Surface treatment configurations may be combined with treatmentprocesses in various surface treatment systems to generate a multitudeof products. Products generated at a site may vary with local and/orglobal market conditions, formation characteristics, proximity offormation to a purchaser, and/or available feedstocks. Generatedproducts may be utilized on site, transferred to another site for use,and/or sold to a purchaser.

[1534] Feedstocks for surface treatment units may be generated intreatment areas and/or surface treatment units. A “feedstock” is astream containing at least one component required for a treatmentprocess. Feedstocks may include, but are not limited to, formationfluid, synthetic condensate, a gas stream, a water stream, a gasfraction, a light fraction, a middle fraction, a heavy fraction,bottoms, a naphtha fraction, a jet fuel fraction, a diesel fraction,and/or a fraction containing a specific component (e.g., heart fraction,phenols containing fraction, etc.). In some embodiments, feedstocks arehydrotreated prior to entering a surface treatment unit. For example, ahydrotreating unit used to hydrotreat a synthetic condensate maygenerate hydrogen sulfide to be utilized in the synthesis of afertilizer such as ammonium sulfate. Alternatively, one or morecomponents (e.g., heavy metals) may have been removed from formationfluids prior to entering the surface treatment unit.

[1535] In alternate embodiments, feedstocks for in situ treatmentprocesses may be generated at the surface in surface treatment units.For example, a hydrogen stream may be separated from formation fluid ina surface treatment unit and then provided to an in situ treatment areato enhance generation of upgraded products. In addition, a feedstock maybe injected into a treatment area to be stored for later use.Alternatively, storage of a feedstock may occur in storage units on thesurface.

[1536] The composition of products generated may be altered bycontrolling conditions within a treatment area and/or within one or moresurface treatment units. Conditions within the treatment area and/or oneor more surface treatment units which affect product compositioninclude, but are not limited to, average temperature, fluid pressure,partial pressure of H₂, temperature gradients, composition of formationmaterial, heating rates, and composition of fluids entering thetreatment area and/or the surface treatment unit. Many different surfacefacility configurations exist for the synthesis and/or separation ofspecific components from formation fluid.

[1537] Formation fluid may be produced from a formation through awellhead. As shown in FIG. 222, wellhead 7012 may separate formationfluid 7010 into gas stream 7022, liquid hydrocarbon condensate stream7024, and water stream 7026. Alternatively, formation fluid may beproduced from a formation through a wellhead and flow to a separatingunit, where the formation fluid is separated into a gas stream, a liquidhydrocarbon condensate stream, and a water stream. A portion of the gasstream, the liquid hydrocarbon condensate stream, and/or the waterstream may flow to one or more surface treatment units for use in atreatment process. Alternatively, a portion of the gas stream, theliquid hydrocarbon condensate stream, and/or the water stream may beprovided to one or more treatment areas.

[1538] In some embodiments, formation fluid may flow directly from theformation to a surface treatment unit to be treated. An advantage oftreating formation fluid before separation may be a reduction in thenumber of surface treatment units required. Reducing the number ofsurface treatment units may result in decreased capital and/or operatingexpenses for a treatment system for formations.

[1539] Formation fluid may exit the formation at a temperature in excessof about 300° C. Utilizing thermal energy within the formation fluid mayreduce an amount of energy required by the treatment system. In certainembodiments, formation fluid produced at an elevated temperature may beprovided to one or more surface treatment units. Formation fluid mayenter the surface treatment unit at a temperature greater than about250° C., 275° C., 300° C., 325° C., or 350° C. Alternatively, thermalenergy from formation fluid may be transferred to other fluids utilizedby the surface facility configuration and/or the in situ treatmentprocess.

[1540] As shown in FIG. 223, formation fluid 7010 produced from wellhead7020 may flow to heat exchange unit 7030. Heat exchange fluid 7034 mayflow into heat exchange unit 7030. Thermal energy from formation fluid7010 may be transferred to heat exchange fluid 7034 in heat exchangeunit 7030 to generate heated fluid 7036 and cooled formation fluid 7032.Heat exchange fluid 7034 may include any fluid stream produced from aformation (e.g., formation fluid, pyrolysis fluid, water, and/orsynthesis gas), and/or any fluid stream generated and/or separated outwithin a surface treatment unit (e.g., water stream, light fraction,middle fraction, heavy fraction, hydrotreated liquid hydrocarboncondensate stream, jet fuel stream, etc.).

[1541] In some in situ conversion process embodiments, a heat exchangeunit may be used to increase a temperature of the formation fluid anddecrease a temperature of the heat exchange fluid to generate a cooledfluid and a heated formation fluid. For example, pyrolysis fluids may beproduced from a first treatment area at a temperature of about 300° C.Synthesis gas may be produced from a second treatment area at atemperature of about 600° C. The pyrolysis fluids and synthesis gas mayflow in separate conduits to distant surface treatment units. Heat lossmay cause the pyrolysis fluids to condense before reaching a distantsurface treatment unit for treatment. Various configurations ofconduits, known in the art, may be used to form a heat exchange unit totransfer thermal energy from the synthesis gas to the pyrolysis fluidsto decrease, or prevent, condensation of the pyrolysis fluids.

[1542] In conventional treatment processes, hydrocarbon fluids producedfrom a formation may be separated into at least two streams, including agas stream and a synthetic condensate stream. The gas stream may containone or more components and may be further separated into componentstreams using one or more surface treatment units. The liquidhydrocarbon condensate stream, or synthetic condensate stream, maycontain one or more components that are separated using one or moresurface treatment units. In some embodiments, formation fluid may bepartially cooled to enhance separation of specific components. Forexample, formation fluid may flow to a heat exchange unit to reduce atemperature of the formation fluid. Then, the formation fluid may beprovided to a separating unit such as a distillation column and/or acondensing unit.

[1543] Formation fluid may be hydrotreated prior to separation into agas stream and a liquid hydrocarbon condensate stream. Alternatively,the gas stream and/or the liquid hydrocarbon condensate stream may behydrotreated in separate hydrotreating units prior to further separationinto component streams. “Synthetic condensate” is the liquid componentof formation fluid that condenses.

[1544] In an embodiment, synthetic condensate 7015 flows to surfacefacilities configuration illustrated in FIG. 224. Synthetic condensate7015 may be separated into several fractions in fractionator 7040. Insome embodiments, synthetic condensate stream 7015 is separated intofour fractions. Light fraction 7042, middle fraction 7044, and heavyfraction 7046 may flow to hydrotreating units 7050, 7052, 7054.Hydrotreating units 7050, 7052, 7054 may upgrade hydrocarbons withinfractions 7042, 7044, and 7046 to form light fraction 7053, middlefraction 7055, and/or heavy fraction 7057. In addition, bottoms fraction7048 may be generated. Bottoms fraction 7048 may flow to an in situtreatment area or a surface facility for further processing. In someembodiments, the use of a synthetic condensate stream from which sulfurcontaining compounds have been removed, for example, by hydrotreating ora liquid-liquid extraction process, may increase an effective life ofthe hydrotreating units.

[1545] In an in situ conversion process embodiment, a fractionation unitmay separate a feedstock into a light fraction, a heart cut, a middlecut, and/or a heavy fraction. The composition of the heart cut may becontrolled by removing fluid for the heart cut at a point in thefractionator having a given temperature. After the heart cut has beenseparated, the heart cut may flow to one or more surface treatment unitsincluding, but not limited to, a hydrotreater, a reformer, a crackingunit, and/or a component recovery unit. For example, when a naphthalenefraction is desired, a heart cut may be taken from a point in thefractionator resulting in production of a stream having an atmosphericpressure true boiling point temperature greater than about 210° C. toless than about 230° C. This may correspond to the boiling point rangefor naphthalene. Components that can be separated from a syntheticcondensate in a “heart cut” may include, but are not limited to,mono-aromatic hydrocarbons (e.g., benzene, toluene, ethyl benzene,and/or xylene), naphthalene, anthracene, and/or phenols.

[1546] Temperatures at which components are separated from the formationfluid during distillation or condensation may be affected by theconcentration of water (e.g., steam) in the formation fluid. Steam maybe present in the formation fluid in varying concentrations, due tovarying water contents of formations and variations in steam generationduring treatment. In some embodiments, a steam content of formationfluid may be measured as the formation fluid is produced. The steamcontent may be used to adjust one or more operating conditions inseparating units to enhance separation of fractions.

[1547] Formation fluid may flow to one or more distillation columnspositioned in series to remove one or more fractions in succession. Theone or more fractions from the fluids may be used in one or more surfacetreatment units. “Serial fractional separation” is the removal of two ormore fractions from formation fluid in series. Some of the formationfluid flows to two or more separation units in series, and eachseparation unit may remove one or more components from the formationfluid. For example, formation fluid may be separated into a gas streamand a synthetic condensate. A “naphtha cut” may be separated from thesynthetic condensate. The “naphtha cut” may be further separated into a“phenols cut.” Separating successively smaller cuts from the formationfluid may allow the subsequent treatment units to be smaller and lesscostly, since only a portion of the formation fluid needs to be treatedto produce a specific product. In addition, molecular hydrogen may beseparated for use in one or more of the upstream or downstreamprocesses.

[1548]FIG. 225 depicts a serial fractional system. Synthetic condensate7015 may flow to separating unit 7060, where it is separated into two ormore fractions: light fraction 7062 and heavy fraction 7064. Lightfraction 7062 may flow to heat exchanger 7065 to generate cooled lightfraction 7066, which is separated into light fraction 7072 in separatingunit 7070. Heat exchanger 7075 may remove thermal energy from lightfraction 7072 to cooled light fraction 7076, which then flows toseparating unit 7080. Naphtha fraction 7082 may be separated from cooledlight fraction 7076. Naphtha fraction 7082 may be further separated intoolefin generating compound fraction 7092 in separating unit 7090 afterbeing cooled in heat exchanger 7085 to form cooled naphtha fraction7086. Olefin generating compound fraction 7092 may flow to an olefingenerating unit to be converted to olefins. Fractions 7064, 7074, 7084,7094 may flow to one or more surface treatment units and/or in situtreatment areas for additional treatment. Extracting thermal energy fromfractions 7062, 7072, 7082, and/or 7092 may increase an energyefficiency of the process by utilizing the heat in the fluids. Inalternate embodiments, light fractions (e.g., light fraction 7062, lightfraction 7072, and/or naphtha fraction 7082) may be heated in heatexchanging units 7065, 7075, 7085 prior to entering the one or moreseparation units.

[1549] As shown in FIG. 226, an embodiment of a surface facility portionutilizes some of heavy fractions 7064, 7074, 7084, 7094 as a recyclestream. Some of heavy fractions 7064, 7074, 7084, 7094 removed fromseparation units 7060, 7070, 7080, 7090 may flow to reboilers 7067,7077, 7087, 7097. Recycle streams 7069, 7079, 7089, 7099 may flow fromreboilers 7067, 7077, 7087, 7097 to separation units 7060, 7070, 7080,7090 for further upgrading. In some embodiments, steam may be providedto heavy fractions 7064, 7074, 7084, 7094 to form recycle streams. Insome embodiments, a separating system for treating formation fluid mayinclude a combination of heat exchangers, reboilers, and/or theinjection of steam.

[1550] In certain surface facility embodiments, catalysts may be used inseparating units to upgrade hydrocarbons in formation fluid as thehydrocarbons are being separated into the various fractions. In someembodiments, reactive separating units may contain catalysts thatenhance hydrocarbon upgrading through hydrotreating. Molecular hydrogenpresent in the feedstock may be sufficient to hydrotreat hydrocarbonswithin the feedstock. In alternate embodiments, molecular hydrogen maybe provided to a feedstock entering a reactive separating unit or to thereactive separating unit to enhance hydrogenation.

[1551] Reactive distillation columns may be used to treat a syntheticcondensate such as synthetic condensate and/or hydrotreated syntheticcondensate in some embodiments. A reactive distillation column maycontain a catalyst to increase hydrotreating of hydrocarbons in fluidspassing through the reactive distillation column. In certainembodiments, the catalyst may be a conventional catalyst such as metalon an alumina substrate.

[1552] As illustrated in FIG. 227, multiple distillation columns 7100,7120, 7130, 7140 may be used to separate synthetic condensate 7015 intofractions. Distillation columns 7100, 7120, 7130, 7140 may containcatalyst 7052, which enables hydrocarbons within synthetic condensate7015 to be upgraded within distillation columns 7100, 7120, 7130, 7140through hydrotreating. Molecular hydrogen stream 7105 may be added todistillation columns 7100, 7120, 7130, 7140 to enhance hydrotreating ofhydrocarbons within synthetic condensate stream 7015 in distillationcolumns 7100, 7120, 7130, 7140. Molecular hydrogen stream 7105 may comefrom surface treatment units and/or produced formation fluids. Fractionsremoved from distillation column 7100 may include light fraction 7102,middle fraction 7104, heavy fraction 7106, and bottoms 7108.

[1553] In an embodiment, light fraction 7102 flows to separating unit7110 that separates light fraction 7102 into gaseous stream 7112, lightfraction 7114, and recycle stream 7116. Light fraction 7114 may flow toreactive distillation column 7120 to be separated and upgraded. Indistillation column 7120, light fraction 7114 may be converted intolight fraction 7122. A portion of light fraction 7122 may flow toreboiler 7125 and then flow to distillation column 7120 as recyclestream 7128. Light stream 7126 may flow to a surface treatment unit suchas a reforming unit, an olefin generating unit, a cracking unit, and/ora separating unit. The reforming unit may alter light stream 7126 togenerate aromatics and hydrogen. Alternatively, light stream 7126 may beused to generate various types of fuel (e.g., gasoline). Light stream7126 may, in certain embodiments, be blended with other hydrocarbonfluids to increase a value and/or a mobility of the hydrocarbon fluids.In some embodiments, light stream 7126 may be a naphtha stream.

[1554] In some embodiments, middle fraction 7104 flows into reactivedistillation column 7130. Middle fraction 7104 may be converted intomiddle fraction 7132 and recycle stream 7134 in reactive distillationcolumn 7130. Recycle stream 7134 may flow into distillation column 7100.A portion of middle fraction 7132 may flow into reboiler unit 7135 to bevaporized and enter distillation column 7130 as recycle stream 7138.Middle stream 7136 may be provided to a market and/or flow to a surfacetreatment unit for further treatment.

[1555] Heavy fraction 7106 may flow into distillation column 7140. Heavyfraction 7142 and recycle stream 7144 may be generated in reactivedistillation column 7140. Recycle stream 7144 may flow into distillationcolumn 7100. A portion of heavy fraction 7142 may flow into reboilerunit 7145 to be vaporized and enters distillation column 7140 as recyclestream 7148. Heavy stream 7146 may be provided to a market and/or flowto a surface treatment unit and/or in situ treatment area for furthertreatment.

[1556] Bottoms fraction 7108 may be removed from distillation column7100. A portion of bottoms fraction 7108 may be vaporized in reboilerunit 7150 and enter distillation column 7100 as recycle stream 7152.Bottoms stream 7109 may be cooled in heat exchange units. In certainembodiments, a portion of a bottoms fraction may be used as a feedstockfor an olefin plant and/or an in situ treatment area. In someembodiments, a portion of a bottoms fraction may flow to a hydrocrackingunit to form a transportation fuel stream.

[1557] In some embodiments, formation fluid produced from the ground maybe partially cooled to recover thermal energy from the fluid. Inaddition, formation fluid may be cooled to a temperature at which adesired component is removed from the formation fluid. Heat exchangingunits may remove thermal energy from the formation fluid such that atemperature within the formation fluid is reduced to a temperature atwhich one or more components are separated from formation fluid.Formation fluid may be provided to a distillation column where theformation fluid is further separated into a liquid stream and a vaporstream. The vapor stream may be provided to a heat exchanging unit toremove thermal energy from the vapor stream. The vapor stream may befurther separated in a distillation column. In some embodiments,multiple distillation columns may be arranged to separate the vaporstream into one or more fractions.

[1558] In some embodiments, formation fluid 7010 flows into condensingunit 7160 as shown in FIG. 228. Condensing unit 7160 may separateformation fluid 7010 into gas fraction 7162, light fraction 7164, heavyfraction 7166, and/or heart cut 7168. Gas fraction 7162, light fraction7164, heavy fraction 7166, and/or heart cut 7168 may flow to a surfacetreatment unit for additional treatment.

[1559] An example of a surface facility configuration for treatingformation fluid is illustrated in FIG. 229. Formation fluid 7010 may beproduced through wellhead 7020 and cooled in one or more heat exchangeunits 7170. Cooled formation fluid 7172 may be condensed in condensingunit 7175 to form condensed formation fluid 7176. Condensed formationfluid 7176 may be separated in processing unit 7180 into gas stream 7182and synthetic condensate 7015. Gas stream 7182 may be compressed andseparated in compressor 7185 into gas stream 7186 and hydrocarboncontaining fluids 7187. Hydrocarbon containing fluids 7187 may be heatedin heater 7188. Heated hydrocarbon containing fluids 7189 may beseparated into gas stream 7192 and naphtha stream 7126 in processingunit 7190. Gas stream 7186 and gas stream 7192 may flow into expander7195. Expander 7195 allows fluids within gas stream 7186 and gas stream7192 to expand into light off-gas 7196.

[1560] In an embodiment, synthetic condensate stream 7015 is pumped tohydrotreating unit 7200 to be hydrotreated. Hydrotreated syntheticcondensate stream 7202 may flow through heat exchanging units 7170 to beheated. Heated and hydrotreated synthetic condensate stream 7205 may beseparated into a mixture of non-condensable hydrocarbons 7208 andhydrocarbon containing fluid 7210 in processing unit 7206. Hydrocarboncontaining fluid 7210 may be pumped through heat exchange units 7170 toform heated hydrocarbon containing fluid 7212. Heated hydrocarboncontaining fluid 7212 may be further heated in heating unit 7214 to formheated hydrocarbon containing fluid 7216. Heated hydrocarbon containingfluid 7216 and non-condensable hydrocarbons 7208 may be distilled indistillation column 7220 to form light fraction 7042, middle fraction7044, heavy fraction 7046, and bottoms 7228. Light fraction 7042 may becooled in heat exchange unit 7234. Cooled light fraction 7222 may beseparated into heavy off-gas 7224, water stream 7272, and hydrocarboncondensate stream 7238 in process unit 7236. Hydrocarbon condensatestream 7238 may be split into at least two streams, including recyclestream 7229 and light fraction 7227. Light fraction 7227 may be added tolight stream 7126. Olefins may be generated from light stream 7126 in areforming unit. Alternatively, light stream 7126 may be used to generatevarious types of fuel. Light stream 7126, in certain embodiments, may beblended with other hydrocarbon fluids to increase a value and/or amobility of the hydrocarbon fluids.

[1561] In some embodiments, middle fraction 7044 flows to distillationcolumn 7240. Recycle stream 7244 and middle fraction 7242 may begenerated in distillation column 7240. Recycle stream 7244 may flow todistillation column 7220. Reboiler 7246 may separate middle fraction7242 into recycle stream 7248 and hot middle fraction 7250. Recyclestream 7248 flows to distillation column 7240. Hot middle fraction 7250may be cooled in heat exchange units 7252 to form cooled middle fraction7254. In addition, cooled middle fraction 7254 may flow into acondensing unit to form a middle stream. Alternatively, hot middlefraction 7250 may flow directly from reboiler 7246 to a condensing unitto form a middle stream.

[1562] In an embodiment, distillation column 7270 separates heavyfraction 7046 into recycle stream 7256 and heavy fraction 7258. Recyclestream 7256 may flow to distillation column 7220. Heavy fraction 7258may flow to reboiler 7260. Reboiler 7260 may separate heavy fraction7258 into recycle stream 7262 and heated heavy fraction 7264. Heatedheavy fraction 7264 may be cooled in heat exchange units 7266 to formcooled heavy fraction 7268. In some embodiments, cooled heavy fraction7268 may flow into a condensing unit. Alternatively, heavy fraction 7264may flow from reboiler 7260 to a condensing unit to form a heavy stream.

[1563] In certain embodiments, bottoms fraction 7228 is removed fromdistillation column 7220 and is cooled in heat exchange units 7230 toform cooled bottoms fraction 7232. In some embodiments, cooled bottomsfraction 7232 may flow into a condensing unit to form a condensate.Alternatively, bottoms fraction 7228 may flow directly from distillationcolumn 7220 to a condensing unit.

[1564] In alternate embodiments, distillation columns 7220, 7240, and/or7270 may contain catalysts to upgrade hydrocarbons. The catalysts may behydrotreating and/or cracking catalysts. In some embodiments, anadditional molecular hydrogen stream may be added to distillationcolumns 7220, 7240, and/or 7270 that contain such catalysts.

[1565] Formation fluid may contain substances that compromise surfacetreatment units by altering catalytic surfaces and/or by causingcorrosion. Many surface treatment units may require the removal of thesesubstances prior to treatment in the surface treatment unit. Componentsin formation fluid that may affect a life span and/or efficiency of thesurface treatment unit include heteroatoms (e.g., nitrogen, sulfur, andwater). For example, water decreases the catalytic ability ofconventional hydrotreating catalysts. In some embodiments, use of aconventional hydrotreating unit may require separation of water fromformation fluid prior to treatment. In addition, sulfur containingcompounds may cause corrosion of a surface treatment unit and decreasethe catalytic ability of certain catalysts used in the surface treatmentunit. Removal of sulfur containing compounds from formation fluid mayincrease the value of produced fluid and permit processing of the lowersulfur material in process units not designed for untreated producedfluid.

[1566] Components that foul or corrode surface treatment units may beremoved using a variety of methods including, but not limited to,hydrotreating, solvent extraction, a desalting process, and/orelectrostatic precipitation. In some embodiments, a portion of the waterpresent in formation fluid may be removed from formation fluid as theformation fluid is separated into a gas stream and a liquid hydrocarboncondensate stream.

[1567] In some embodiments, a desalting process may reduce salts information fluid and/or any water or fluid separated in a surfacetreatment unit. The desalting process may include, but is not limitedto, chemical separation, electrostatic separation, and/or filtration ofwater/fluid through a porous structure (e.g., water or fluid may befiltered through diatomaceous earth).

[1568] Heteroatoms may also be removed from formation fluid using anextraction process. Solvents may include, but are not limited to, aceticacid, sulfuric acid, and/or formic acid. Heteroatoms in acidic form,such as phenols and some sulfur compounds, may be removed by extractionwith basic solutions (e.g., caustic or aqueous ammonia). Extraction mayvary with a temperature of formation fluid and/or solvent, a solvent tooil ratio, and/or an acid strength of the acidic solvents. An effectivesolvent may be characterized by features including, but not limited to,inhibition of emulsion formation, immiscibility with feedstock, rapidphase separation, and/or high capacity. Removal of nitrogen containingcomponents by an extraction process may decrease hydrogen uptake and thehydrotreating severity required in subsequent hydrotreating units,thereby reducing operating and capital costs.

[1569] Enactment of more stringent regulatory standards for sulfur inhydrocarbon containing products may require a higher severity to removesulfur from the products. In some circumstances, sulfur may be removedfrom formation fluid prior to separating the fluid into streams tofacilitate removal of a maximum amount of sulfur. Similarly, formationfluid may be hydrotreated prior to separation into streams to decreasean overall cost of processing formation fluid. Subsequent sulfur removaland/or hydrotreating may further improve the quality of hydrocarbonfluids produced from the formation fluid.

[1570] Conventional refiners may not handle high concentrations ofheteroatoms in fluid fractions (e.g., naphtha, jet, and diesel).Hydrotreating may produce a product that would be acceptable to arefiner. Another approach, or a complementary approach, may be tooptimize the combination of the in situ conversion process conditionsand surface hydrotreating processes to obtain the highest product valuemix at the lowest total cost. For example, one in situ conversionprocess change that may improve properties of the liquid formation fluidis the use of backpressure on the formation during the heating process.Maintaining a fluid pressure by adjusting the backpressure may produce amuch lighter and more hydrogen rich product.

[1571] Hydrotreating a fluid may alter many properties of the fluid.Hydrotreating may increase the hydrogen content of the hydrocarbonswithin the fluid and/or the volume of fluid. In addition, hydrotreatingmay reduce a content of heteroatoms such as oxygen, nitrogen, or sulfurin the fluid. For example, nitrogen removed from the fluid duringhydrotreating may be converted into ammonia. Removed sulfur may beconverted into hydrogen sulfide. Feedstocks for hydrotreating units mayinclude, but are not limited to, formation fluid and/or any fluidgenerated or separated in a surface treatment unit (e.g., syntheticcondensate, light fraction, middle fraction, heavy fraction, bottoms,heart cut, pyrolysis gasoline, and/or molecular hydrogen generated at anolefin generating plant).

[1572] Olefins may be present in formation fluid as a result of in situtreatment processes. In some embodiments, olefin generating compoundsmay be produced in formation fluid. “Olefin generating compounds” arehydrocarbons having a carbon number equal to and/or greater than 2 andless than 30 (e.g., carbon numbers from 2 to 7). These olefin generatingcompounds may be converted into olefins, such as ethylene and propylene.Process conditions during treatment within a treatment area of aformation may be controlled to increase, or even to maximize, productionof olefins and/or olefin generating compounds within the formationfluid.

[1573] In an embodiment, olefins and/or olefin generating compoundsproduced in the formation fluid may be separated from the formationfluid using one or more surface facility configurations. Separation ofolefins and/or olefin generating compounds from formation fluid mayoccur in, but is not limited to, a gas treating unit, a distillationunit, and/or a condensing unit. Olefin generating compounds may beseparated from formation fluid to form an olefin feedstock used togenerate olefins.

[1574] Olefin feedstocks may include formation fluid, syntheticcondensate, a naphtha stream, a heart cut (e.g., a stream containinghydrocarbons having carbon number from two to seven), a propane stream,and/or an ethane stream. For example, formation fluid may be separatedinto a liquid stream (e.g., synthetic condensate) and a gas stream. Thegas stream may be further separated into four or more fractions. Thefractions may include, but are not limited to, a methane fraction, amolecular hydrogen fraction, a gas fraction, and an olefin generatingcompound fraction. In some embodiments, olefin feedstocks may have beenhydrotreated and/or have had one or more components (e.g., arsenic,lead, mercury, etc.) removed prior to entering the olefin generatingunit.

[1575] Many different surface facility configurations may produceolefins from an olefin feedstock. The particular configuration utilizedfor synthesis of olefins may depend on a type of formation treated, acomposition of formation fluid, and/or treatment process conditions usedin situ such as a temperature, a pressure, a partial pressure of H₂,and/or a rate of heating.

[1576] Conversion of formation fluid and/or olefin generating compoundsto olefins occurs when hydrocarbons in formation fluid are heatedrapidly to cracking temperatures and then quenched rapidly to inhibitsecondary reactions (e.g., recombination of hydrogen with olefins).Prolonged heating may result in the production of coke and, thus,quenching the reaction is vital to enhancing olefin generation. Atemperature required for olefin generation may be greater than about800° C. Formation fluid may exit the formation at a temperature greaterthan about 200° C. In certain embodiments, formation fluid may beproduced from wells containing a heat source such that a temperature ofat least a portion of the formation fluid is about 700° C. Therefore,additional heating may be required for generation of olefins. Formationfluid may flow to an olefin generating unit where fluid is initiallyheated and then cooled to quench the reaction to enhance production ofolefins.

[1577]FIG. 230 depicts an embodiment of surface facility units used togenerate olefins from an olefin feedstock that contains olefingenerating compounds. The hydrogen content of hydrocarbons withinformation fluid may be increased to greater than about 12 weight % bycontrolling one or more conditions within a treatment area from whichformation fluid 7010 is produced. For example, maintaining a pressuregreater than about 7 bars (100 psig) and a temperature less than about375° C. within a treatment area may generate formation fluid havinghydrocarbons with a hydrogen content greater than about 12 weight %. Ahydrogen content of greater than 12 weight % in the hydrocarbons offormation fluid may decrease the content of heavy hydrocarbons and/orundesirable compounds in the formation fluid produced.

[1578] In an embodiment, formation fluid 7010 (e.g., formation fluidhaving hydrocarbons with a hydrogen content greater than about 12%)flows directly from wellhead 7020 into olefin generating unit 7280 to beconverted to olefin stream 7282. In some embodiments, the olefingenerating unit may be a steam cracker. Formation fluid 7010 may flowinto olefin generating unit 7280 at a temperature greater than about300° C. in certain embodiments. Thermal energy within the formationfluid may be utilized in the generation of olefins from the olefingenerating compounds. In an embodiment, formation fluid may containsteam. Steam in formation fluid may be utilized in the generation ofolefins. A portion of the steam required for the generation of olefinsin an olefin generating unit may be provided by steam present information fluid.

[1579] Alternatively, formation fluid may flow to a component removalunit prior to an olefin generating unit. In certain embodiments,formation fluid may include components containing small amounts of heavymetals such as arsenic, lead, and/or mercury. As depicted in FIG. 231,treatment unit 7290 may separate formation fluid 7010 into two componentstreams (e.g., streams 7292, 7294) and hydrocarbon containing fluids7296. Component streams 7292, 7294 may include a single component or amixture of multiple components. For example, treatment unit 7290 mayremove heavy metals in streams 7292, 7294. Hydrocarbon containing stream7296 may flow to olefin generating unit 7280 to be converted to olefinstream 7282. Olefin stream 7282 may include, but is not limited to,ethylene, propylene, and/or butylene.

[1580] Molecular hydrogen within an olefin feedstock may be removed fromthe olefin feedstock prior to the feedstock being provided to an olefingenerating unit in some embodiments. In alternate embodiments, formationfluid may flow to a hydrotreating unit prior to flowing to an olefingenerating unit to convert at least a portion of the olefin generatingcompounds into olefins.

[1581] In an olefin generating unit, a portion of the formation fluidmay be converted into compounds which may include, but are not limitedto, olefins, molecular hydrogen, pyrolysis gasoline that contains BTEXcompounds (benzene, toluene, ethylbenzene and/or xylene), pyrolysispitch, and/or butadiene. In some embodiments, the molecular hydrogengenerated in the olefin generating unit may flow to a hydrotreating unitto hydrotreat fluids. For example, a portion of the generated molecularhydrogen may be used to hydrotreat pyrolysis gasoline and/or pyrolysispitch generated in the olefin generating unit. Alternatively, a portionof the generated molecular hydrogen may be provided to an in situtreatment area.

[1582] In some embodiments, a portion of fluid generated in an olefingenerating unit may flow to one or more extraction units to removecomponents such as butadiene and/or BTEX compounds. In some embodiments,pyrolysis gasoline generated in an olefin generating unit may have ahigh BTEX content. Pyrolysis gasoline may, in certain embodiments, beprovided to a surface treatment unit to remove the BTEX compounds. Insome embodiments, pyrolysis pitch may be used as a fuel. Alternatively,pyrolysis pitch may be provided to an in situ treatment area foradditional processing.

[1583] A steam cracking unit may be utilized as an olefin generatingunit as depicted in FIG. 232. Steam cracking unit 7310 may includeheating unit 7320 and quenching unit 7330. Olefin feedstock 7300entering heating unit 7320 may be heated to a temperature greater thanabout 800° C. Fluid 7322 may flow to quenching unit 7330 to rapidlyquench and compress fluid 7322. Fluid 7332 exiting quenching unit 7330may include one or more olefin compounds, molecular hydrogen, and/orBTEX compounds. The olefin compounds may include, but are not limitedto, ethylene, propylene, and/or butylene. In certain embodiments, fluid7332 may flow to a separating unit. The components within fluid 7332 maybe separated into component streams in the separating unit. Thecomponent streams may be sold, transported to a different facility,stored for later use, and/or utilized on site in treatment areas or insurface treatment units.

[1584] Ammonia may be generated during an in situ conversion process. Insitu ammonia may be generated during a pyrolysis stage from some of thenitrogen present in hydrocarbon material. Hydrogen sulfide may also beproduced within the formation from some of the sulfur present in thehydrocarbon containing material. The ammonia and hydrogen sulfidegenerated in situ may be dissolved in water condensed from the formationfluids.

[1585]FIG. 233 depicts a configuration of surface treatment units thatmay separate ammonia and hydrogen sulfide from water produced in theformation. Formation fluid 7010 may be separated at wellhead 7012 intogas stream 7022, synthetic condensate 7015, and water stream 7026. Gastreating unit 7350 may separate gas stream 7022 into gas mixture 7352,light hydrocarbon mixture 7354, and/or hydrogen fraction 7356. Gasmixture 7352 may include, but is not limited to, hydrogen sulfide,carbon dioxide, and/or ammonia. Gas mixture 7352 may be blended withwater stream 7026 to form aqueous mixture 7358. Aqueous mixture 7358 mayflow to stripping unit 7360, where aqueous mixture 7358 is separatedinto ammonia stream 7362 and aqueous mixture 7364. Aqueous mixture 7364may flow to stripping unit 7370 to be separated into hydrogen sulfidestream 7372 and water stream 7374. Ammonia stream 7362 may be stored asan aqueous solution or in anhydrous form. Alternately, ammonia stream7362 may be provided to surface treatment units requiring ammonia, suchas a urea synthesis unit or an ammonium sulfate synthesis unit.

[1586] In some embodiments, ammonia may be formed from nitrogen presentin hydrocarbons when fluids are being hydrotreated. The generatedammonia may also be separated from other components, as illustrated inFIG. 234. Synthetic condensate 7015 may flow to hydrotreating unit 7380to form ammonia containing stream 7382 and hydrotreated syntheticcondensate 7384. Ammonia containing stream 7382 may be blended withwater stream 7026 and gas mixture 7352 prior to entering stripping unit7360 as aqueous mixture 7386.

[1587] Alternatively, fluid containing small amounts or concentrationsof ammonia may flow to Claus treatment unit 7390 for treatment, asdepicted in FIG. 235. Wellhead 7012 may separate formation fluid 7010into gas stream 7022, synthetic condensate 7015, and water stream 7026.Gas treating unit 7350 may further separate gas stream 7022 into gasmixture 7352, light hydrocarbon mixture 7354, and/or hydrogen fraction7356. Water stream 7026 and gas mixture 7352 may be blended to formstream 7358. Claus treatment unit 7390 may reduce ammonia in stream 7358to form fluid stream 7394. Recovered sulfur may exit Claus treatmentunit 7390 as sulfur stream 7392 and be utilized in any process thatrequires sulfur, either in surface facilities or treatment areas. Insome embodiments, Claus treatment unit 7390 may also generate a carbondioxide stream. The carbon dioxide may be utilized in a urea synthesisunit. Alternatively, carbon dioxide may be provided to an in situtreatment area for sequestration.

[1588] If a hydrotreating unit is used, then at least a portion of thesulfur in the stream entering the hydrotreating unit may be converted tohydrogen sulfide. In some embodiments, hydrogen sulfide may be used tomake fertilizer, sulfuric acid, and/or converted to sulfur in a Claustreatment unit. Similarly, some nitrogen in the stream entering thehydrotreating unit may be converted to ammonia, which may also berecovered for sale and/or use in processes.

[1589] In some embodiments, ammonia may be generated on site in surfacetreatment units using an ammonia synthesis process as shown in FIG. 236.Air stream 7400 may flow to air separating unit 7410 to separatenitrogen stream 7412 and stream 7414 from air stream 7400. Nitrogenstream 7412 may be heated with heat exchanger 7170 to form heatednitrogen feedstock 7416 prior to flowing into ammonia generating unit7420. Hydrogen feedstock 7418 may flow to ammonia generating unit 7420to react with nitrogen stream 7412 to form ammonia stream 7422. Ammoniagenerated during in situ or surface treatment processes may be stored inan aqueous solution or as anhydrous ammonia. In some instances, ammoniain either form may be sold commercially. Alternatively, ammonia may beused on site to generate a number of different products that havecommercial value (e.g., fertilizers such as ammonium sulfate and/orurea). Production of fertilizer may increase the economic viability of atreatment system used to treat a formation. Precursors for fertilizerproduction may be produced in situ or while treating formation fluid atsurface facilities.

[1590] Ammonia and carbon dioxide generated during treatment either insitu or at a surface treating unit may be used to generate urea for useas a fertilizer, as illustrated in FIG. 237. Ammonia stream 7424 andcarbon dioxide stream 7426 may react in urea generating unit 7428 toform urea stream 7430.

[1591] As illustrated in FIG. 238, ammonium sulfate may be generated bytreating formation fluid in a surface treatment unit. Wellhead 7012 mayseparate formation fluid 7010 into a mixture of non-condensablehydrocarbon fluids 7432 and synthetic condensate 7015. Separation unit7434 may be used to separate non-condensable hydrocarbon fluids 7432into hydrogen stream 7436, hydrogen sulfide stream 7438, methane stream7440, carbon dioxide stream 7442, and non-condensable hydrocarbon fluids7444.

[1592] Hydrogen sulfide stream 7438 may flow to oxidation unit 7446 tobe converted to sulfuric acid stream 7450. Additional hydrogen sulfidemay, in certain embodiments, be provided to oxidation unit 7446 fromhydrogen sulfide stream 7448. In some embodiments, hydrogen sulfidestream 7448 may be provided from a hydrotreating unit. The hydrotreatingunit may be a surface facility in a different section of a treatmentsystem or part of a different configuration of a treatment system.

[1593] Air separating unit 7410 may be used to separate nitrogen stream7412 and stream 7414 from air stream 7400. Heat exchanger 7170 may heatnitrogen stream 7412 to form heated nitrogen feedstock 7416. Hydrogenstream 7436 and heated nitrogen feedstock 7416 may flow to ammoniagenerating unit 7420 to form ammonia stream 7422. In some embodiments,additional hydrogen may be provided to ammonia generating unit 7420. Inalternate embodiments, a portion of hydrogen stream 7436 may flow to anin situ treatment area and/or a surface treatment facility. In certainembodiments, process ammonia 7452, produced in formation fluid and/orgenerated in surface treatment units, is added to ammonia stream 7422 toform ammonia feedstock 7454.

[1594] Ammonia feedstock 7454 and sulfuric acid stream 7450 may flowinto fertilizer synthesis unit 7456 to produce ammonium sulfate stream7458. Alternatively, a portion of sulfuric acid produced in an oxidationunit may be sold commercially.

[1595] In some embodiments, ammonia produced during treatment of aformation may be used to generate ammonium carbonate, ammoniumbicarbonate, ammonium carbamate, and/or urea. Separated ammonia may beprovided to a stream containing carbon dioxide (e.g., synthesis gasand/or carbon dioxide separated from formation fluid) such that theseparated ammonia reacts with carbon dioxide in the stream to generateammonium carbonate, ammonium bicarbonate, ammonium carbamate, and/orurea. Utilization of separated ammonia in this manner may reduce carbondioxide emissions from a treatment process. Ammonium carbonate, ammoniumbicarbonate, ammonium carbamate, and/or urea may be commerciallymarketed to a local market for use (e.g., as a fertilizer or a materialto make fertilizer). Ammonium carbonate, ammonium bicarbonate, ammoniumcarbamate, and/or urea may capture or sequester carbon dioxide ingeologic formations.

[1596] In some embodiments, formation fluid may include a significantamount of phenols. The amount of phenols produced from a formationdepends on the amount of oxygenated aromatic hydrocarbons in thekerogenous materials in the formation. “Phenols” refers to aromaticrings with an attached OH group, including substituted aromatic ringssuch as cresol, xylenol, etc. The amount of phenols in producedformation fluid may depend on operating conditions in the formation(e.g., formation heating rate, temperature gradients in the formation,fluid pressure in the formation, partial pressure of molecular hydrogenin the formation, and/or an average temperature within the formation).Controlling one or more of these conditions may affect the carbondistribution in the formation fluid. As an average carbon distributionis lowered, a fraction having a carbon number greater than or equal to 6and a carbon number less than or equal to 8 may increase. This fractionmay correlate to the phenols fraction in the formation fluid.

[1597] In an embodiment, a method for treating an oil shale formation insitu may include controlling a pressure of a selected section of theformation and/or the hydrogen partial pressure in the selected sectionof the formation such that production of phenols from the selectedsection is increased. For example, the amount of phenols tends todecrease as the pressure of the formation is increased and vice versa.The partial pressure of hydrogen in the formation may be changed byadding hydrogen to the formation or by adding a compound such as steamto the formation.

[1598] In certain embodiments, when the pressure (or partial pressure ofhydrogen) is increased, the production of phenol may also increase whilethe production of all phenols decreases. It is believed that some of thesubstituted groups from substituted aromatic rings (such as cresol,xylenol, etc.) may be replaced with hydrogen under higher pressures. Insome embodiments, a temperature and/or a heating rate may be controlledto increase the production of phenols from a selected section of theformation. The total amount of phenols produced tends to remainrelatively constant since the amount of liquids produced tends toincrease as the weight percent of phenols in the liquids decreased.

[1599] Extraction of phenols from an oil shale formation may increasethe economic viability of an in situ treatment system. Separatingphenols from formation fluid may increase the total value of generatedproducts. Phenols in a relatively concentrated form may have a highereconomic value than phenols as a component in formation fluid. Inaddition, removing phenols from formation fluid may reduce the cost ofhydrotreating by reducing hydrogen consumption (i.e., transformingoxygen and hydrogen to water) in hydrotreating units and/or reactors, aswell as reducing the volume of fluids being hydrotreated.

[1600] Formations may be selected for treatment due to the oxygencontent of a portion of the formation. The oxygen content of the portionmay be indicative of the phenols content producible from the portion.The formation or at least one portion thereof may be sampled todetermine the oxygen content in the formation.

[1601] In some embodiments, formation fluid may be provided to a phenolsextraction unit directly after production from a formation.Alternatively, formation fluid may be treated using one or more surfacetreatment units prior to flowing to a phenols extraction unit. Fluidsprovided to a phenols extraction unit may a “phenols rich” feedstock.The phenols rich feedstock may include, but is not limited to, formationfluid, synthetic condensate, a naphtha stream, and/or phenols richfractions.

[1602] Conditions within a treatment area of a formation may becontrolled to increase, or even maximize, production of phenols information fluid. FIG. 239 depicts surface treatment units used toseparate phenols from formation fluid 7010. Formation fluid may beseparated in phenols extraction unit 7460 into phenols fraction 7462 andfraction 7464. In some embodiments, phenols extraction unit 7460 mayutilize water and/or methanol to extract phenols. In certainembodiments, phenols fraction 7462 may flow to purifying unit 7466.Purifying unit 7466 may generate phenols stream 7468. Phenols stream7468 may be sold commercially, stored on site, transported off site,and/or utilized in other treatment processes.

[1603] In some embodiments, the phenols extraction unit may separate aphenols rich feedstock into two or more streams. The two or more streamsmay include a hydrocarbon stream and/or a phenol stream. In addition,alternate streams which may be separated from the phenols rich feedstockin the phenols extraction unit may include, but are not limited to, aphenol stream, a cresol stream, a xylenol stream, a phenol-cresolstream, a cresol-xylenol stream, and/or any combination thereof. Forexample, the phenols rich feedstock may be separated into four streamsincluding a hydrocarbon stream, a phenol stream, a cresol stream, and axylenol stream.

[1604] In some embodiments, phenols may be recovered from a portion offormation fluid. Treating a portion of formation fluid may reducecapital and operating costs of a phenols extraction unit by reducing thevolume of fluids being treated. The portion of formation fluid providedto the phenols extraction unit may be a phenols rich feedstock (e.g.,synthetic condensate, light fraction, naphtha fraction, and/or phenolscontaining fraction). In the phenols extraction unit, the phenols richfraction may be separated into a phenols fraction and a hydrocarbonfraction. The phenols fraction may, in certain embodiments, flow to apurifying unit to remove one or more components.

[1605] Alternatively, phenols may be separated from formation fluid bycondensation and/or distillation of formation fluid to form a phenolscontaining fraction. The phenols containing fraction may include, but isnot limited to, a naphtha fraction, a phenols fraction, a phenolfraction, a cresol fraction, a phenol-cresol fraction, a xylenolfraction, and/or a cresol-xylenol fraction.

[1606] Molecular hydrogen may, in certain embodiments, be utilized toselectively convert phenols (e.g., xylenols) other than phenol withinthe phenols containing stream to achieve a desired phenol content in thegenerated fluid. For example, xylenols and cresols may be cracked in thepresence of molecular hydrogen to form phenol. Production of phenol froma mixture of xylenols is described in U.S. Pat. No. 2,998,457 issued toPaulsen, et al., which is incorporated by reference as if fully setforth herein. These reactions may occur using hydrocracking conditionsin the presence of a catalyst containing approximately 10-15 weight %chromia on a high purity low sodium content gamma type alumina support.Feedstocks generated as a result of an in situ conversion process may besubjected to the above described treatment process to increase a contentof phenol.

[1607] Formation fluid may include mono-aromatic components such asbenzene, toluene, ethyl benzene, and xylene, (i.e., BTEX compounds). Insome embodiments, separating BTEX compounds from formation fluid mayincrease an economic value of the generated products. Separated BTEXcompounds may have a higher economic value than the same BTEX compoundsin the mixture of component in the formation fluid. BTEX compounds maybe separated from a synthetic condensate stream. “Synthetic condensate”may refer to a liquid hydrocarbon condensate stream and/or ahydrotreated liquid condensate stream.

[1608] A process embodiment may include separating synthetic condensate7015 into BTEX compound stream 7472 and BTEX compound reduced syntheticcondensate 7474 using separating unit 7470, as illustrated in FIG. 240.Mono-aromatic reduced synthetic condensate 7474 may flow tohydrotreating unit 7476, where BTEX compound reduced syntheticcondensate 7474 is hydrotreated to form hydrotreated syntheticcondensate 7478. Hydrotreated synthetic condensate 7478 may flow to anysurface treatment unit for further treatment. Alternatively,mono-aromatic reduced synthetic condensate 7474 may, in certainembodiments, flow to a surface treatment unit for further treatment.

[1609] Mono-aromatic components, specifically BTEX compounds, may alsobe recovered after a synthetic condensate stream has been separated intoone or more fractions (e.g., a naphtha fraction, a jet fraction, and/ora diesel fraction). The naphtha fraction may be separated from formationfluid using a surface treatment unit. In some embodiments, removal ofBTEX compounds prior to hydrotreating the naphtha fraction may reducecapital and operating costs of a hydrotreating unit needed to treat thenaphtha fraction. In certain embodiments, a naphtha fraction may behydrotreated.

[1610] In some embodiments, formation fluid may contain BTEX generatingcompounds such as paraffins and/or naphthalene. BTEX generatingcompounds may flow to one or more surface treatment units to beconverted into BTEX compounds. In some embodiments, a syntheticcondensate may be hydrotreated and then separated in separating units toform a naphtha stream. The naphtha stream may be provided to a reformerunit that converts BTEX generating compounds to BTEX compounds.

[1611] Naphtha stream 7480 may flow to reforming unit 7482, asillustrated in FIG. 241. Naphtha stream 7480 may be converted intoreformate 7484 and hydrogen stream 7486. In certain embodiments,hydrogen stream 7486 flows to any surface treatment unit and/ortreatment area requiring hydrogen. For example, a hydrotreating unitand/or a reactive distillation column may utilize hydrogen stream 7486.Reformate 7484 may flow to recovery unit 7488. Reformate 7484 may beseparated into mono-aromatic stream 7492 and raffinate 7490 in recoveryunit 7488. In some embodiments, raffinate 7490 may flow to a processingunit to be converted to a gasoline stream. The gasoline may be providedto a local market. In alternate embodiments, a mono-aromatic recoveryunit may separate reformate 7484 into one or more streams, such asraffinate 7490, a benzene stream, a toluene stream, a ethyl benzenestream, and/or a xylene stream. In certain embodiments, naphtha stream7480 may be replaced with a “heart cut” (i.e., products distilled in arelatively narrow selected temperature range) corresponding tomono-aromatic compounds.

[1612] Conversion of BTEX generating compounds into BTEX compounds inreforming unit 7482 may form molecular hydrogen. The molecular hydrogenmay be used in one or more surface treatment units and/or in situtreatment areas where molecular hydrogen is needed. An advantage ofutilizing a reforming unit may be the generation of molecular hydrogenfor use on site. Generating molecular hydrogen on site may lower capitalas well as operating costs for a given treatment system.

[1613] Formation fluid produced from oil shale formations during an insitu conversion process may contain one or more components (e.g.,naphthalene, anthracene, pyridine, pyrroles, and/or thiophene and itshomologs). Various operating conditions within a treatment area may becontrolled to increase the production of a component. Some of thecomponents may be commercially viable products. Separating somecomponents from formation fluid may increase the total value ofgenerated products. A separated component in relatively concentratedform may have higher economic value than the same component in formationfluid. For example, formation fluid containing naphthalene may be soldat a lower price than a naphthalene stream separated from the formationfluid and the remaining formation fluid. In an embodiment, separation ofnaphthalenes may be accomplished using crystallization. In addition,removal of some components may reduce hydrogen consumption in subsequenthydrotreating units.

[1614]FIG. 242 depicts an embodiment of recovery unit 7496 used toseparate a component from heart cut 7494. Heart cut 7494 may be obtainedfrom a synthetic crude or formation fluid. Heart cut 7494 flows torecovery unit 7496, which may separate heart cut 7494 into componentstream 7498 and hydrocarbon mixture 7450. In some embodiments, componentstream 7498 may be sold and/or used on site in an in situ treatment areaand/or a surface treatment unit. Hydrocarbon mixture 7450 may flow toone or more treatment units for additional treatment or, in someembodiments, to an in situ treatment area.

[1615] In some embodiments, the recovery unit, as shown in FIG. 242,separates the component from a feedstock stream (e.g., formation fluid,synthetic condensate, a gas stream, a light fraction, a middle fraction,a heavy fraction, bottoms, a naphtha stream, a jet fuel stream, a dieselstream, etc). Recovery units may separate more than one component fromthe feedstock stream in certain embodiments. For example, a recoveryunit may separate a feedstock stream into a naphthalene stream, ananthracene stream, a naphthalene/anthracene stream, and/or a hydrocarbonmixture. Fluids generated during an in situ conversion process maycontain naphthalene and/or anthracene.

[1616] When nitrogen containing components (e.g., pyridines andpyrroles) are to be separated from a feedstock, the recovery unit may bea nitrogen extraction unit. In some embodiments, a nitrogen extractionunit may separate the nitrogen containing components using a sulfuricacid process or a formic acid process. Nitrogen extraction units mayinclude sulfuric acid extraction units and/or closed cycle formic acidextraction units. A sulfuric acid process may separate a portion of theformation fluid into a raffinate and an extract oil. The extract oil maycontain pyridines and other nitrogen containing compounds, as well asspent acid. The extract oil may be separated into a nitrogen richextract and an acid stream.

[1617] Shale oil produced from an in situ thermal conversion process mayhave major components in the desirable naphtha, jet, and diesel boilingrange. The shale oil, however, may also contain a significant amount ofnitrogen compounds. Methods to remove the nitrogen compounds include,but are not limited to, hydrotreating and/or solvent extraction. Studiesof various solvent extraction configurations were completed to determinethe optimal conditions and/or materials for removing nitrogen compoundsfrom oil produced during the in situ conversion process in an oil shaleformation.

[1618] A successful extraction process exhibits the followingproperties: inhibition of emulsion formation, immiscibility with thefeedstock, rapid phase separation, and high capacity. An initialscreening of the first three properties was used to direct laterstudies.

[1619] All the solvents tested during the initial screening developed adeep red color upon mixing with the shale oil, indicating that somecomponents from the shale oil were partitioned into the solvent. Afurther indication of extraction efficiency was an increase in solventvolume. In a perfectly selective system (e.g., where only thosemolecules containing nitrogen were removed), the volume gain would beabout 16%.

[1620] The initial screening studies were conducted using shale oil andfour solvents. Solvents evaluated included sulfuric acid, formic acid,1-methyl-2-pyrrolidinone (NMP), and acetic acid. Extraction severity wasvaried by changing the acid strength, the temperature, and the solventto oil ratios. All experiments used 10 cm³ of a solvent/water mixtureand 10 cm³ of oil mixed at room temperature for 1 minute in a 14 g vial(8 dram vial).

[1621] In the initial screening using acetic acid, only the experimentusing 100% acetic acid resulted in an increase in volume with noemulsion formation and a reasonable separation time of approximately 15minutes. Concentrations of acetic acid greater than 30 weight %increased the required extract volume, and no emulsions were formed.Phase separation times ranging from approximately 5 to 10 minutes wereacceptable. Sulfuric acid was the next solvent tested. Whenconcentrations of sulfuric acid were less than 70 weight %, an emulsionformed. At higher concentrations, however, the light color of theraffinate indicated that a large percentage of the polynuclear aromaticcompounds, including nitrogen compounds, were extracted. The finalsolvent tested in the initial screening was 1-methyl-2-pyrrolidinone(NMP). Extractions using concentrations greater than 90 weight % NMP hadan increase in extract volume as well as no emulsion formation. Thephase separation time, however, ranged from 45 to 240 minutes.

[1622] The initial study determined a range of concentrations for eachsolvent for which there was an increase in extract volume, no emulsionformation, and reasonable phase separation times. The solventconcentrations included greater than 30 weight % formic acid, greaterthan 70 weight % sulfuric acid, greater than 30 weight % NMP, and 100%acetic acid.

[1623] Experiments were performed in a batch mode using 1 L or 2 Lseparatory funnel 7460, as shown in FIG. 243. Weighed amounts of solvent7462 and water 7464 were mixed and added to separatory funnel 7460,followed by shale oil 7466. The total volumes were usually in the rangeof 500-800 mL for the 1 L experiments and about 1200-1600 mL for the 2 Lexperiments. For extractions performed at elevated temperatures, thesolvent and oil were equilibrated for 40 minutes in a 19 L (5 gallon)metal can filled with water that was heated to the desired temperature.The mixture was vigorously shaken for 1 minute and then allowed to phaseseparate. In most cases, 30 minutes were allowed for separation intoraffinate 7470 and solvent layer 7472, but in some cases (e.g., withsulfuric acid), the phase separation was much quicker.

[1624] Some experiments, called “crosscurrent contacting,” involved aseries of sequential contacting steps. For example, in a two-stepcrosscontacting, the raffinate phase from the first contact would becontacted with a second aliquot of fresh solvent. The overallsolvent/oil ratio reported reflects the total volume of solvent used forall contacts.

[1625] To evaluate the suitability of the extracted oil as a feedstockfor a refinery, a large sample was prepared and distilled into fourproduct cuts. Based on initial 1 L studies, the optimum formic acidconcentration was 85.3 weight %. Five crosscurrent extractions werecarried out with an overall solvent to oil ratio of 0.65. The raffinateproducts were combined prior to distillation.

[1626] The first solvent tested was 1-methyl-2-pyrrolidinone (NMP). Theraffinate fraction generated contained a higher weight percentage, andin some cases a significantly higher weight percentage, of nitrogencompounds than the feedstock. The solubility of the NMP in the oil phasewas significant. Consequently, as the nitrogen compounds in shale oilwere extracted into the NMP, some of the NMP was partitioned into theraffinate layer. With concentrations greater than 90 weight %, anincrease in extract volume was observed as well as no emulsionformation, however, the phase separation time ranged from 45 to 240minutes.

[1627] The acetic acid extraction using a 99.9 weight % acetic acidsolution exhibited 88.4 weight % nitrogen compound removal and 88 weight% raffinate yield. A crosscurrent experiment indicated, however, thatsome acetic acid was partitioned into the raffinate layer.

[1628] Preliminary experiments with formic acid were carried out at 40°C. with a 1 L glass separatory funnel. A temperature of 40° C. wasinitially chosen as a value close to the highest temperature that couldbe used in an atmospheric extraction, since the initial boiling point ofthe oil was about 50° C. Higher extraction temperatures may haveresulted in significant losses of oil in these simple extractionstudies.

[1629] Acid concentrations were initially varied between 85-88 weight %,and both single step and crosscurrent extractions were investigated. Theraffinate yields varied between 82-87 weight % and the level of nitrogenextraction varied between 90-92 weight %. The results exceeded thetarget of greater than 90 weight % nitrogen removal with an oil yieldgreater than 83 weight %.

[1630] Based on the initial studies, five extractions were conductedusing a 2 L separatory funnel. The total amount of oil extracted was 4.0L. The acid concentration was 85.4 weight %, and each extraction wascarried out in crosscurrent fashion with three contacts of fresh acidwith the oil. The average nitrogen compound removal was 92 weight % (880ppm), and the overall raffinate oil yield was 83.7 weight %. Theraffinate product was distilled into four fractions: naphtha (20.2weight %), jet (37.1 weight %), diesel (26.3 weight %), and residue(15.2 weight %). In addition, there was approximately 1 weight % oflight material that appeared to be primarily formic acid. While over 90weight % of the nitrogen compounds were removed, some nitrogen compoundsremained in each of the fractions. The naphtha fraction contained about70 ppm nitrogen. The high jet smoke point of 20 mm and cetane index of55 for the diesel indicated that commercial products could be made fromthese two fractions.

[1631] A simpler process with no acid recycle was also examined usingsulfuric acid as the solvent. A series of experiments was carried out toexamine extraction efficiency. With a solvent to oil ratio of 0.074 andan acid concentration of 93 weight %, the sulfuric acid removed 97weight % of the nitrogen compounds (229 ppm product nitrogen), and theraffinate yield was 82 weight %. Higher sulfuric acid/oil ratiosextracted more nitrogen compounds. A 90 weight % sulfuric acidconcentration with an acid/oil ratio of 1.0 removed 99.8 weight %nitrogen compounds (27 ppm product nitrogen), with a yield of 76 weight%. Lower acid concentrations removed fewer nitrogen compounds.

[1632] Sulfuric acid extractions with a solvent to oil ratio of 0.074and a single contacting of 93 weight % sulfuric acid removed 97 weight %of the nitrogen compounds. The raffinate oil yield was 82 weight %. Theformic acid experiments required higher concentrations of acid toextract the nitrogen compounds compared to sulfuric acid. Contacting theoil at room temperature with a 94 weight % formic acid solvent using asolvent to oil ratio of 1.0 removed 92 weight % of the nitrogencompounds from the oil and resulted in an oil yield of 86 weight %.

[1633] Removal of greater than 90% of the nitrogen compounds andmaintaining an oil yield greater than 83 weight % was achieved with twoof the solvents tested, specifically sulfuric acid and formic acid. Thesulfuric acid extractions required low solvent to oil ratios to achievethe desired nitrogen compound removal. Contacting the oil with 93 weight% sulfuric acid solvent using a solvent to oil ratio of 0.074, 97 weight% of the nitrogen compounds were removed and the raffinate oil yield was82 weight %. With a single room temperature contacting of 94 weight %formic acid at a 1.0 solvent to oil ratio, 92 weight % of nitrogencompounds were removed.

[1634]FIG. 244 depicts an embodiment of treatment areas 8000 surroundedby perimeter barrier 8002. Each treatment area 8000 may be a volume offormation that is, or is to be, subjected to an in situ conversionprocess. Perimeter barrier 8002 may include installed portions andnaturally occurring portions of the formation. Naturally occurringportions of the formation that form part of a perimeter barrier mayinclude substantially impermeable layers of the formation. Examples ofnaturally occurring perimeter barriers include overburdens andunderburdens. Installed portions of perimeter barrier 8002 may be formedas needed to define separate treatment areas 8000. In situ conversionprocess (ICP) wells 8004 may be placed within treatment areas 8000. ICPwells 8004 may include heat sources, production wells, treatment areadewatering wells, monitor wells, and other types of wells used during insitu conversion.

[1635] Different treatment areas 8000 may share common barrier sectionsto minimize the length of perimeter barrier 8002 that needs to beformed. Perimeter barrier 8002 may inhibit fluid migration intotreatment area 8000 undergoing in situ conversion. Advantageously,perimeter barrier 8002 may inhibit formation water from migrating intotreatment area 8000. Formation water typically includes water anddissolved material in the water (e.g., salts). If formation water wereallowed to migrate into treatment area 8000 during an in situ conversionprocess, the formation water might increase operating costs for theprocess by adding additional energy costs associated with vaporizing theformation water and additional fluid treatment costs associated withremoving, separating, and treating additional water in formation fluidproduced from the formation. A large amount of formation water migratinginto a treatment area may inhibit heat sources from raising temperatureswithin portions of treatment area 8000 to desired temperatures.

[1636] Perimeter barrier 8002 may inhibit undesired migration offormation fluids out of treatment area 8000 during an in situ conversionprocess. Perimeter barriers 8002 between adjacent treatment areas 8000may allow adjacent treatment areas to undergo different in situconversion processes. For example, a first treatment area may beundergoing pyrolysis, a second treatment area adjacent to the firsttreatment area may be undergoing synthesis gas generation, and a thirdtreatment area adjacent to the first treatment area and/or the secondtreatment area may be subjected to an in situ solution mining process.Operating conditions within the different treatment areas may be atdifferent temperatures, pressures, production rates, heat injectionrates, etc.

[1637] Perimeter barrier 8002 may define a limited volume of formationthat is to be treated by an in situ conversion process. The limitedvolume of formation is known as treatment area 8000. Defining a limitedvolume of formation that is to be treated may allow operating conditionswithin the limited volume to be more readily controlled. In someformations, a hydrocarbon containing layer that is to be subjected to insitu conversion is located in a portion of the formation that ispermeable and/or fractured. Without perimeter barrier 8002, formationfluid produced during in situ conversion might migrate out of the volumeof formation being treated. Flow of formation fluid out of the volume offormation being treated may inhibit the ability to maintain a desiredpressure within the portion of the formation being treated. Thus,defining a limited volume of formation that is to be treated by usingperimeter barrier 8002 may allow the pressure within the limited volumeto be controlled. Controlling the amount of fluid removed from treatmentarea 8000 through pressure relief wells, production wells and/or heatsources may allow pressure within the treatment area to be controlled.In some embodiments, pressure relief wells are perforated casings placedwithin or adjacent to wellbores of heat sources that have sealedcasings, such as flameless distributed combustors. The use of some typesof perimeter barriers (e.g., frozen barriers and grout walls) may allowpressure control in individual treatment areas 8000.

[1638] Uncontrolled flow or migration of formation fluid out oftreatment area 8000 may adversely affect the ability to efficientlymaintain a desired temperature within treatment area 8000. Perimeterbarrier 8002 may inhibit migration of hot formation fluid out oftreatment area 8000. Inhibiting fluid migration through the perimeter oftreatment area 8000 may limit convective heat losses to heat loss influid removed from the formation through production wells and/or fluidremoved to control pressure within the treatment area.

[1639] During in situ conversion, heat applied to the formation maycause fractures to develop within treatment area 8000. Some of thefractures may propagate towards a perimeter of treatment area 8000. Apropagating fracture may intersect an aquifer and allow formation waterto enter treatment area 8000. Formation water entering treatment area8000 may not permit heat sources in a portion of the treatment area toraise the temperature of the formation to temperatures significantlyabove the vaporization temperature of formation water entering theformation. Fractures may also allow formation fluid produced during insitu conversion to migrate away from treatment area 8000.

[1640] Perimeter barrier 8002 around treatment area 8000 may limit theeffect of a propagating fracture on an in situ conversion process. Insome embodiments, perimeter barriers 8002 are located far enough awayfrom treatment areas 8000 so that fractures that develop in theformation do not influence perimeter barrier integrity. Perimeterbarriers 8002 may be located over 10 m, 40 m, or 70 m away from ICPwells 8004. In some embodiments, perimeter barrier 8002 may be locatedadjacent to treatment area 8000. For example, a frozen barrier formed byfreeze wells may be located close to heat sources, production wells, orother wells. ICP wells 8004 may be located less than 1 m away fromfreeze wells, although a larger spacing may advantageously limitinfluence of the frozen barrier on the ICP wells, and limit theinfluence of formation heating on the frozen barrier.

[1641] In some perimeter barrier embodiments, and especially for naturalperimeter barriers, ICP wells 8004 may be placed in perimeter barrier8002 or next to the perimeter barrier. For example, ICP wells 8004 maybe used to treat hydrocarbon layer 516 that is a thin rich hydrocarbonlayer. The ICP wells may be placed in overburden 540 and/or underburden8010 adjacent to hydrocarbon layer 516, as depicted in FIG. 245. ICPwells 8004 may include heater-production wells that heat the formationand remove fluid from the formation. Thin rich layer hydrocarbon layer516 may have a thickness greater than about 0.2 m and less than about 8m, and a richness of from about 205 liters of oil per metric ton toabout 1670 liters of oil per metric ton. Overburden 540 and underburden8010 may be portions of perimeter barrier 8002 for the in situconversion system used to treat rich thin layer 516. Heat losses tooverburden 540 and/or underburden 8010 may be acceptable to produce richhydrocarbon layer 516. In other ICP well placement embodiments fortreating thin rich hydrocarbon layers 516, ICP wells 8004 may be placedwithin hydrocarbon layer 516, as depicted in FIG. 246.

[1642] In some in situ conversion process embodiments, a perimeterbarrier may be self-sealing. For example, formation water adjacent to afrozen barrier formed by freeze wells may freeze and seal the frozenbarrier should the frozen barrier be ruptured by a shift or fracture inthe formation. In some in situ conversion process embodiments, progressof fractures in the formation may be monitored. If a fracture that ispropagating towards the perimeter of the treatment area is detected, acontrollable parameter (e.g., pressure or energy input) may be adjustedto inhibit propagation of the fracture to the surrounding perimeterbarrier.

[1643] Perimeter barriers may be useful to address regulatory issuesand/or to insure that areas proximate a treatment area (e.g., watertables or other environmentally sensitive areas) are not substantiallyaffected by an in situ conversion process. The formation within theperimeter barrier may be treated using an in situ conversion process.The perimeter barrier may inhibit the formation on an outer side of theperimeter barrier from being affected by the in situ conversion processused on the formation within the perimeter barrier. Perimeter barriersmay inhibit fluid migration from a treatment area. Perimeter barriersmay inhibit rise in temperature to pyrolysis temperatures on outer sidesof the perimeter barriers.

[1644] Different types of barriers may be used to form a perimeterbarrier around an in situ conversion process treatment area. Theperimeter barrier may be, but is not limited to, a frozen barriersurrounding the treatment area, dewatering wells, a grout wall formed inthe formation, a sulfur cement barrier, a barrier formed by a gelproduced in the formation, a barrier formed by precipitation of salts inthe formation, a barrier formed by a polymerization reaction in theformation, sheets driven into the formation, or combinations thereof.

[1645]FIG. 247 depicts a side representation of a portion of anembodiment of treatment area 8000 having perimeter barrier 8002 formedby overburden 540, underburden 8010, and freeze wells 8012 (only onefreeze well is shown in FIG. 247). A portion of freeze well 8012 andperimeter barrier 8002 formed by the freeze well extend into underburden8010. In some embodiments, perimeter barrier 8002 may not extend intounderburden 8010 (e.g., a perimeter barrier may extend into hydrocarbonlayer 516 reasonably close to the underburden or some of the hydrocarbonlayer may function as part of the perimeter barrier). Underburden 8010may be a rock layer that inhibits fluid flow into or out of treatmentarea 8000. In some embodiments, a portion of the underburden may behydrocarbon containing material that is not to be subjected to in situconversion.

[1646] Overburden 540 may extend over treatment area 8000. Overburden540 may include a portion of hydrocarbon containing material that is notto be subjected to in situ conversion. Overburden 540 may inhibit fluidflow into or out of treatment area 8000.

[1647] Some formations may include underburden 8010 that is permeable orincludes fractures that would allow fluid flow into or out of treatmentarea 8000. A portion of perimeter barrier 8002 may be formed belowtreatment area 8000 to inhibit inflow of fluid into the treatment areaand/or to inhibit outflow of formation fluid during in situ conversion.FIG. 248 depicts treatment area 8000 having a portion of perimeterbarrier 8002 that is below the treatment area. The perimeter barrier maybe a frozen barrier formed by freeze wells 8012. In some embodiments, aperimeter barrier below a treatment area may follow along a geologicalformation.

[1648] Some formations may include overburden 540 that is permeable orincludes fractures that allow fluid flow into or out of treatment area8000. A portion of perimeter barrier 8002 may be formed above thetreatment area to inhibit inflow of fluid into the treatment area and/orto inhibit outflow of formation fluid during in situ conversion. FIG.248 depicts an embodiment of an in situ conversion process having aportion of perimeter barrier 8002 formed above treatment area 8000. Insome embodiments, a perimeter barrier above a treatment area may followalong a geological formation (e.g., along dip of a dipping formation).In some embodiments, a perimeter barrier above a treatment area may beformed as a ground cover placed at or near the surface of the formation.Such a perimeter barrier may allow for treatment of a formation whereina hydrocarbon layer to be processed is close to the surface.

[1649] In some formations, water may flow through a fracture system inan oil shale formation. Perimeter barriers may be inserted through theoverburden, through the hydrocarbon layer, and into the underburden toform a treatment area. The inserted perimeter barrier, the overburden,and the underburden may form perimeter barriers that define a treatmentarea.

[1650] As depicted in FIG. 244, several perimeter barriers 8002 may beformed to divide a formation into treatment areas 8000. If a largeamount of water is present in the hydrocarbon containing material,dewatering wells may be used to remove water in the treatment area aftera perimeter barrier is formed. If the hydrocarbon containing materialdoes not contain a large amount of water, heat sources may be activated.The heat sources may vaporize water within the formation, and the watervapor may be removed from the treatment area through production wells.

[1651] A perimeter barrier may have any desired shape. In someembodiments, portions of perimeter barriers may follow along geologicalfeatures and/or property lines. In some embodiments, portions ofperimeter barriers may have circular, square, rectangular, or polygonalshapes. Portions of perimeter barriers may also have irregular shapes. Aperimeter barrier having a circular shape may advantageously enclose alarger area than other regular polygonal shapes that have the sameperimeter. For example, for equal perimeters, a circular barrier willenclose about 27% more area than a square barrier. Using a circularperimeter barrier may require fewer wells and/or less material toenclose a desired area with a perimeter barrier than would other regularperimeter barrier shapes. In some embodiments, square, rectangular orother polygonal perimeter barriers are used to conform to property linesand/or to accommodate a regular well pattern of heat sources andproduction wells.

[1652] A formation that is to be treated using an in situ conversionprocess may be separated into several treatment areas by perimeterbarriers. FIG. 244 depicts an embodiment of a perimeter barrierarrangement for a portion of a formation that is to be processed usingsubstantially rectangular treatment areas 8000. A perimeter barrier fortreatment area 8000 may be formed when needed. The complete pattern ofperimeter barriers for all of the formation to be subjected to in situconversion does not need to be formed prior to treating individualtreatment areas.

[1653] Perimeter barriers having circular or arced portions may beplaced in a formation in a regular pattern. Centers of the circular orarced portions may be positioned at apices of imaginary polygonpatterns. For example, FIG. 249 depicts a pattern of perimeter barrierswherein a unit of the pattern is based on an equilateral triangle. FIG.250 depicts a pattern of perimeter barriers wherein a unit of thepattern is based on a square. Perimeter barrier patterns may also bebased on higher order polygons.

[1654]FIG. 249 depicts a plan view representation of a perimeter barrierembodiment that forms treatment areas 8000 in a formation. Centers ofarced portions of perimeter barriers 8002 are positioned at apices ofimaginary equilateral triangles. The imaginary equilateral triangles aredepicted as dashed lines. First circular barrier 8002′ may be formed inthe formation to define first treatment area 8000′.

[1655] Second barrier 8002″ may be formed. Second barrier 8002″ andportions of first barrier 8002′ may define second treatment area 8000″.Second barrier 8002″ may have an arced portion with a radius that issubstantially equal to the radius of first circular barrier 8002′. Thecenter of second barrier 8002″ may be located such that if the secondbarrier were formed as a complete circle, the second barrier wouldcontact the first barrier substantially at a tangent point. Secondbarrier 8002″ may include linear sections 8014 that allow for a largerarea to be enclosed for the same or a lesser length of perimeter barrierthan would be needed to complete the second barrier as a circle. In someembodiments, second barrier 8002″ may not include linear sections andthe second barrier may contact the first barrier at a tangent point orat a tangent region. Second treatment area 8000″ may be defined byportions of first circular barrier 8002′ and second barrier 8002″. Thearea of second treatment area 8000″ may be larger than the area of firsttreatment area 8000′.

[1656] Third barrier 8002′″ may be formed adjacent to first barrier8002′ and second barrier 8002″. Third barrier 8002′″ may be connected tofirst barrier 8002′ and second barrier 8002″ to define third treatmentarea 8000′″. Additional barriers may be formed to form treatment areasfor processing desired portions of a formation.

[1657]FIG. 250 depicts a plan view representation of a perimeter barrierembodiment that forms treatment areas 8000 in a formation. Centers ofarced portions of perimeter barriers 8002 are positioned at apices ofimaginary squares. The imaginary squares are depicted as dashed lines.First circular barrier 8002′ may be formed in the formation to definefirst treatment area 8000′. Second barrier 8002″ may be formed around aportion of second treatment area 8000″. Second barrier 8002″ may have anarced portion with a radius that is substantially equal to the radius offirst circular barrier 8002′. The center of second barrier 8002″ may belocated such that if the second barrier were formed as a completecircle, the second barrier would contact the first barrier at a tangentpoint. Second barrier 8002″ may include linear sections 8014 that allowfor a larger area to be enclosed for the same or a lesser length ofperimeter barrier than would be needed to complete the second barrier asa circle. Two additional perimeter barriers may be formed to complete aunit of four treatment areas.

[1658] In some embodiments, central area 8016 may be isolated byperimeter barrier 8002. For perimeter barriers based on a squarepattern, such as the perimeter barriers depicted in FIG. 250, centralarea 8016 may be a square. A length of a side of the square may be up toabout 0.586 times a radius of an arc section of a perimeter barrier.Surface facilities, or a portion of the surface facilities, used totreat fluid removed from the formation may be located in central area8016. In other embodiments, perimeter barrier segments that form acentral area may not be installed.

[1659]FIG. 251 depicts an embodiment of a barrier configuration in whichperimeter barriers 8002 are formed radially about a central point. In anembodiment, surface facilities for processing production fluid removedfrom the formation are located within central area 8016 defined by firstbarrier 8002′. Locating the surface facilities in the center may reducethe total length of piping needed to transport formation fluid to thetreatment facilities. In alternate embodiments, ICP wells are installedin the central area and surface facilities are located outside of thepattern of barriers.

[1660] A ring of formation between second barrier 8002″ and firstbarrier 8002′ may be treatment area 8000′. Third barrier 8002′″ may beformed around second barrier 8002″. The pattern of barriers may beextended as needed. A ring of formation between an inner barrier and anouter barrier may be a treatment area. If the area of a ring is toolarge to be treated as a whole, linear sections 8014 extending from theinner barrier to the outer barrier may be formed to divide the ring intoa number of treatment areas. In some embodiments, distances betweenbarrier rings may be substantially the same. In other embodiments, adistance between barrier rings may be varied to adjust the area enclosedby the barriers.

[1661] In some embodiments of in situ conversion processes, formationwater may be removed from a treatment area before, during, and/or afterformation of a barrier around the formation. Heat sources, productionwells, and other ICP wells may be installed in the formation before,during, or after formation of the barrier. Some of the production wellsmay be coupled to pumps that remove formation water from the treatmentarea. In other embodiments, dewatering wells may be formed within thetreatment area to remove formation water from the treatment area.Removing formation water from the treatment area prior to heating topyrolysis temperatures for in situ conversion may reduce the energyneeded to raise portions of the formation within the treatment area topyrolysis temperatures by eliminating the need to vaporize all formationwater initially within the treatment area.

[1662] In some embodiments of in situ conversion processes, freeze wellsmay be used to form a low temperature zone around a portion of atreatment area. “Freeze well” refers to a well or opening in a formationused to cool a portion of the formation. In some embodiments, thecooling may be sufficient to cause freezing of materials (e.g.,formation water) that may be present in the formation. In otherembodiments, the cooling may not cause freezing to occur; however, thecooling may serve to inhibit the flow of fluid into or out of atreatment area by filling a portion of the pore space with liquid fluid.

[1663] In some embodiments, freeze wells may be used to form a sideperimeter barrier, or a portion of a side perimeter barrier, in aformation. In some embodiments, freeze wells may be used to form abottom perimeter barrier, or a portion of a bottom perimeter barrier,underneath a formation. In some embodiments, freeze wells may be used toform a top perimeter barrier, or a portion of a top perimeter barrier,above a formation.

[1664] In some embodiments, freeze wells may be maintained attemperatures significantly colder than a freezing temperature offormation water. Heat may transfer from the formation to the freezewells so that a low temperature zone is formed around the freeze wells.A portion of formation water that is in, or flows into, the lowtemperature zone may freeze to form a barrier to fluid flow. Freezewells may be spaced and operated so that the low temperature zone formedby each freeze well overlaps and connects with a low temperature zoneformed by at least one adjacent freeze well.

[1665] Sections of freeze wells that are able to form low temperaturezones may be only a portion of the overall length of the freeze wells.For example, a portion of each freeze well may be insulated adjacent toan overburden so that heat transfer between the freeze wells and theoverburden is inhibited. The freeze wells may form a low temperaturezone along sides of a hydrocarbon containing portion of the formation.The low temperature zone may extend above and/or below a portion of thehydrocarbon containing layer to be treated by in situ conversion. Theability to use only portions of freeze wells to form a low temperaturezone may allow for economic use of freeze wells when forming barriersfor treatment areas that are relatively deep within the formation.

[1666] A perimeter barrier formed by freeze wells may have severaladvantages over perimeter barriers formed by other methods. A perimeterbarrier formed by freeze wells may be formed deep within the ground. Aperimeter barrier formed by freeze wells may not require aninterconnected opening around the perimeter of a treatment area. Aninterconnected opening is typically needed for grout walls and someother types of perimeter barriers. A perimeter barrier formed by freezewells develops due to heat transfer, not by mass transfer. Gel, polymer,and some other types of perimeter barriers depend on mass transferwithin the formation to form the perimeter barrier. Heat transfer in aformation may vary throughout a formation by a relatively small amount(e.g., typically by less than a factor of 2 within a formation layer).Mass transfer in a formation may vary by a much greater amountthroughout a formation (e.g., by a factor of 10⁸ or more within aformation layer). A perimeter barrier formed by freeze wells may havegreater integrity and be easier to form and maintain than a perimeterbarrier that needs mass transfer to form.

[1667] A perimeter barrier formed by freeze wells may provide a thermalbarrier between different treatment areas and between surroundingportions of the formation that are to remain untreated. The thermalbarrier may allow adjacent treatment areas to be subjected to differentprocesses. The treatment areas may be operated at different pressures,temperatures, heating rates, and/or formation fluid removal rates. Thethermal barrier may inhibit hydrocarbon material on an outer side of thebarrier from being pyrolyzed when the treatment area is heated.

[1668] Forming a frozen perimeter barrier around a treatment area withfreeze wells may be more economical and beneficial over the life of anin situ conversion process than operating dewatering wells around thetreatment area. Freeze wells may be less expensive to install, operate,and maintain than dewatering wells. Casings for dewatering wells mayneed to be formed of corrosion resistant metals to withstand corrosionfrom formation water over the life of an in situ conversion process.Freeze wells may be made of carbon steel. Dewatering wells may enhancethe spread of formation fluid from a treatment area. Water produced fromdewatering wells may contain a portion of formation fluid. Such watermay need to be treated to remove hydrocarbons and other material beforethe water can be released. Dewatering wells may inhibit the ability toraise pressure within a treatment area to a desired value sincedewatering wells are constantly removing fluid from the formation.

[1669] Water presence in a low temperature zone may allow for theformation of a frozen barrier. The frozen barrier may be a monolithic,impermeable structure. After the frozen barrier is established, theenergy requirements needed to maintain the frozen barrier may besignificantly reduced, as compared to the energy costs needed toestablish the frozen barrier. In some embodiments, the reduction in costmay be a factor of 10 or more. In other embodiments, the reduction incost may be less dramatic, such as a reduction by a factor of about 3 or4.

[1670] In many formations, hydrocarbon containing portions of theformation are saturated or contain sufficient amounts of formation waterto allow for formation of a frozen barrier. In some formations, watermay be added to the formation adjacent to freeze wells after and/orduring formation of a low temperature zone so that a frozen barrier willbe formed.

[1671] In some in situ conversion embodiments, a low temperature zonemay be formed around a treatment area. During heating of the treatmentarea, water may be released from the treatment area as steam and/orentrained water in formation fluids. In general, when a treatment areais initially heated, water present in the formation is mobilized beforesubstantial quantities of hydrocarbons are produced. The water may befree water and/or released water that was attached or bound to clays orminerals (“bound water”). Mobilized water may flow into the lowtemperature zone. The water may condense and subsequently solidify inthe low temperature zone to form a frozen barrier.

[1672] Pyrolyzing hydrocarbons and/or oxidizing hydrocarbons may formwater vapor during in situ conversion. A significant portion of thegenerated water vapor may be removed from the formation throughproduction wells. A small portion of the generated water vapor maymigrate towards the perimeter of the treatment area. As the waterapproaches the low temperature zone formed by the freeze wells, aportion of the water may condense to liquid water in the low temperaturezone. If the low temperature zone is cold enough, or if the liquid watermoves into a cold enough portion of the low temperature zone, the watermay solidify.

[1673] In some embodiments, freeze wells may form a low temperature zonethat does not result in solidification of formation fluid. For example,if there is insufficient water or other fluid with a relatively highfreezing point in the formation around the freeze wells, then the freezewells may not form a frozen barrier. Instead, a low temperature zone maybe formed. During an in situ conversion process, formation fluid maymigrate into the low temperature zone. A portion of formation fluid(e.g., low freezing point hydrocarbons) may condense in the lowtemperature zone. The condensed fluid may fill pore space within the lowtemperature zone. The condensed fluid may form a barrier to additionalfluid flow into or out of the low temperature zone. A portion of theformation fluid (e.g., water vapor) may condense and freeze within thelow temperature zone to form a frozen barrier. Condensed formation fluidand/or solidified formation fluid may form a barrier to further fluidflow into or out of the low temperature zone.

[1674] Freeze wells may be initiated a significant time in advance ofinitiation of heat sources that will heat a treatment area. Initiatingfreeze wells in advance of heat source initiation may allow for theformation of a thick interconnected frozen perimeter barrier beforeformation temperature in a treatment area is raised. In someembodiments, heat sources that are located a large distance away from aperimeter of a treatment area may be initiated before, simultaneouslywith, or shortly after initiation of freeze wells.

[1675] Heat sources may not be able to break through a frozen perimeterbarrier during thermal treatment of a treatment area. In someembodiments, a frozen perimeter barrier may continue to expand for asignificant time after heating is initiated. Thermal diffusivity of ahot, dry formation may be significantly smaller than thermal diffusivityof a frozen formation. The difference in thermal diffusivities betweenhot, dry formation and frozen formation implies that a cold zone willexpand at a faster rate than a hot zone. Even if heat sources are placedrelatively close to freeze wells that have formed a frozen barrier(e.g., about 1 m away from freeze wells that have established a frozenbarrier), the heat sources will typically not be able to break throughthe frozen barrier if coolant is supplied to the freeze wells. Incertain ICP system embodiments, freeze wells are positioned asignificant distance away from the heat sources and other ICP wells. Thedistance may be about 3 m, 5 m, 10 m, 15 m, or greater.

[1676] The frozen barrier formed by the freeze wells may expand on anoutward side of the perimeter barrier even when heat sources heat theformation on an inward side of the perimeter barrier.

[1677]FIG. 244 depicts a representation of freeze wells 8012 installedin a formation to form low temperature zones 8017 around treatment areas8000. Fluid in low temperature zones 8017 with a freezing point above atemperature of the low temperature zones may solidify in the lowtemperature zones to form perimeter barrier 8002. Typically, the fluidthat solidifies to form perimeter barrier 8002 will be a portion offormation water. Two or more rows of freeze wells may be installedaround treatment area 8000 to form a thicker low temperature zone 8017than can be formed using a single row of freeze wells. FIG. 252 depictstwo rows of freeze wells 8012 around treatment area 8000. Freeze wells8012 may be placed around all of treatment area 8000, or freeze wellsmay be placed around a portion of the treatment area. In someembodiments, natural fluid flow barriers (such as unfractured,substantially impermeable formation material) and/or artificial barriers(e.g., grout walls or interconnected sheet barriers) surround remainingportions of the treatment area when freeze wells do not surround all ofthe treatment area.

[1678] If more than one row of freeze wells surrounds a treatment area,the wells in a first row may be staggered relative to wells in a secondrow. In the freeze well arrangement embodiment depicted in FIG. 252,first separation distance 8018 exists between freeze wells 8012 in a rowof freeze wells. Second separation distance 8020 exists between freezewells 8012 in a first row and a second row. Second separation distance8020 may be about 10-75% (e.g., 30-60% or 50%) of first separationdistance 8018. Other separation distances and freeze well patterns mayalso be used.

[1679]FIG. 248 depicts an embodiment of an ICP system with freeze wells8012 that form low temperature zone 8017 below a portion of a formation,a low temperature zone above a portion of a formation, and a lowtemperature zone along a perimeter of a portion of the formation.Portions of heat sources 8022 and portions of production wells 8024 maypass through low temperature zone 8017 formed by freeze wells 8012. Theportions of heat sources 8022 and production wells 8024 that passthrough low temperature zone 8017 may be insulated to inhibit heattransfer to the low temperature zone. The insulation may include, but isnot limited to, foamed cement, an air gap between an insulated linerplaced in the production well, or a combination thereof.

[1680] A portion of a freeze well that is to form a low temperature zonein a formation may be placed in the formation in desired spaced relationto an adjacent freeze well or freeze wells so that low temperature zonesformed by the individual freeze wells interconnect to form a continuouslow temperature zone. In some freeze well embodiments, each freeze wellmay have two or more sections that allow for heat transfer with anadjacent formation. Other sections of the freeze wells may be insulatedto inhibit heat transfer with the adjacent formation.

[1681] Freeze wells may be placed in the formation so that there isminimal deviation in orientation of one freeze well relative to anadjacent freeze well. Excessive deviation may create a large separationdistance between adjacent freeze wells that may not permit formation ofan interconnected low temperature zone between the adjacent freezewells. Factors that may influence the manner in which freeze wells areinserted into the ground include, but are not limited to, freeze wellinsertion time, depth that the freeze wells are to be inserted,formation properties, desired well orientation, and economics.Relatively low depth freeze wells may be impacted and/or vibrationallyinserted into some formations. Freeze wells may be impacted and/orvibrationally inserted into formations to depths from about 1 m to about100 m without excessive deviation in orientation of freeze wellsrelative to adjacent freeze wells in some types of formations. Freezewells placed deep in a formation or in formations with layers that aredifficult to drill through may be placed in the formation by directionaldrilling and/or geosteering. Directional drilling with steerable motorsuses an inclinometer to guide the drilling assembly. Periodic gyro logsare obtained to correct the path. An example of a directional drillingsystem is VertiTrak™ available from Baker Hughes Inteq (Houston, Tex.).Geosteering uses analysis of geological and survey data from an activelydrilling well to estimate stratigraphic and structural position neededto keep the wellbore advancing in a desired direction. Electrical,magnetic, and/or other signals produced in an adjacent freeze well mayalso be used to guide directionally drilled wells so that a desiredspacing between adjacent wells is maintained. Relatively tight controlof the spacing between freeze wells is an important factor in minimizingthe time for completion of a low temperature zone.

[1682]FIG. 253 depicts a representation of an embodiment of freeze well8012 that is directionally drilled into a formation. Freeze well 8012may enter the formation at a first location and exit the formation at asecond location so that both ends of the freeze well are above theground surface. Refrigerant flow through freeze well 8012 may reduce thetemperature of the formation adjacent to the freeze well to form lowtemperature zone 8017. Refrigerant passing through freeze well 8012 maybe passed through an adjacent freeze well or freeze wells. Temperatureof the refrigerant may be monitored. When the refrigerant temperatureexceeds a desired value, the refrigerant may be directed to arefrigeration unit or units to reduce the temperature of the refrigerantbefore recycling the refrigerant back into the freeze wells. The use offreeze wells that both enter and exit the formation may eliminate theneed to accommodate an inlet refrigerant passage and an outletrefrigerant passage in each freeze well.

[1683] Freeze well 8012 depicted in the embodiment of FIG. 253 formspart of frozen barrier 8002 below water body 8026. Water body 8026 maybe any type of water body such as a pond, lake, stream, or river. Insome embodiments, the water body may be a subsurface water body such asan underground stream or river. Freeze well 8012 is one of many freezewells that may inhibit downward migration of water from water body 8026to hydrocarbon containing layer 516.

[1684]FIG. 254 depicts a representation of freeze wells 8012 used toform a low temperature zone on a side of hydrocarbon containing layer516. In some embodiments, freeze wells 8012 may be placed in anon-hydrocarbon containing layer that is adjacent to hydrocarboncontaining layer 516. In the depicted embodiment, freeze wells 8012 areoriented along dip of hydrocarbon containing layer 516. In someembodiments, freeze wells may be inserted into the formation from twodifferent directions or substantially perpendicular to the groundsurface to limit the length of the freeze wells. Freeze well 8012′ andother freeze wells may be inserted into hydrocarbon containing layer 516to form a perimeter barrier that inhibits fluid flow along thehydrocarbon containing layer. If needed, additional freeze wells may beinstalled to form perimeter barriers to inhibit fluid flow into or fromoverburden 540 or underburden 8010.

[1685] As depicted in FIG. 247, freeze wells 8012 may be positionedwithin a portion of a formation. Freeze wells 8012 and ICP wells mayextend through overburden 540, through hydrocarbon layer 516, and intounderburden 8010. In some embodiments, portions of freeze wells and ICPwells extending through the overburden 540 may be insulated to inhibitheat transfer to or from the surrounding formation.

[1686] In some embodiments, dewatering wells 8028 may extend intoformation 516. Dewatering wells 8028 may be used to remove formationwater from hydrocarbon containing layer 516 after freeze wells 8012 formperimeter barrier 8002. Water may flow through hydrocarbon containinglayer 516 in an existing fracture system and channels. Only a smallnumber of dewatering wells 8028 may be needed to dewater treatment area8000 because the formation may have a large permeability due to theexisting fracture system and channels. Dewatering wells 8028 may beplaced relatively close to freeze wells 8012. In some embodiments,dewatering wells may be temporarily sealed after dewatering. Ifdewatering wells are placed close to freeze wells or to a lowtemperature zone formed by freeze wells, the dewatering wells may befilled with water. Expanding low temperature zone 8017 may freeze thewater placed in the freeze wells to seal the freeze wells. Dewateringwells 8028 may be re-opened after completion of in situ conversion.After in situ conversion, dewatering wells 8028 may be used during cleanup procedures for injection or removal of fluids.

[1687] In some embodiments, selected production wells, heat sources, orother types of ICP wells may be temporarily converted to dewateringwells by attaching pumps to the selected wells. The converted wells maysupplement dewatering wells or eliminate the need for separatedewatering wells. Converting other wells to dewatering wells mayeliminate costs associated with drilling wellbores for dewatering wells.

[1688]FIG. 255 depicts a representation of an embodiment of a wellsystem for treating a formation. Hydrocarbon containing layer 516 mayinclude leached/fractured portion 8030 and non-leached/non-fracturedportion 8032. Formation water may flow through leached/fractured portion8030. Non-leached/non-fractured portion 8032 may be unsaturated andrelatively dry. In some formations, leached/fractured portion 8030 maybe beneath 100 m or more of overburden 540, and the leached/fracturedportion may extend 200 m or more into the formation.Non-leached/non-fractured portion 8032 may extend 400 m or more deeperinto the formation.

[1689] Heat sources 8022 may extend to underburden 8010 belownon-leached/non-fractured portion 8032. Production wells may extend intothe non-leached/non-fractured portion of the formation. The productionwells may have perforations, or be open wellbores, along the portionsextending into the leached/fractured portion andnon-leached/non-fractured portions of the hydrocarbon containing layer.Freeze wells 8012 may extend close to, or a short distance into,non-leached/non-fractured portion 8032. Freeze wells 8012 may be offsetfrom heat sources 8022 and production wells a distance sufficient toallow hydrocarbon material below the freeze wells to remain unpyrolyzedduring treatment of the formation (e.g., about 30 m). Freeze wells 8012may inhibit formation water from flowing into hydrocarbon containinglayer 516. Advantageously, freeze wells 8012 do not need to extend alongthe full length of hydrocarbon material that is to be subjected to insitu conversion, because non-leached/non-fractured portion 8032 beneathfreeze wells 8012 may remain untreated. If treatment of the formationgenerates thermal fractures in the non-leached/non-fractured portion8032 that propagate towards and/or past freeze wells 8012, the fracturesmay remain substantially horizontally oriented. Horizontally orientedfractures will not intersect the leached/fractured portion 8030 to allowformation water to enter into treatment area 8000.

[1690] Various types of refrigeration systems may be used to form a lowtemperature zone. Determination of an appropriate refrigeration systemmay be based on many factors, including, but not limited to: type offreeze well; a distance between adjacent freeze wells; refrigerant; timeframe in which to form a low temperature zone; depth of the lowtemperature zone; temperature differential to which the refrigerant willbe subjected; chemical and physical properties of the refrigerant;environmental concerns related to potential refrigerant releases, leaks,or spills; economics; formation water flow in the formation; compositionand properties of formation water; and various properties of theformation such as thermal conductivity, thermal diffusivity, and heatcapacity.

[1691] Several different types of freeze wells may be used to form a lowtemperature zone. The type of freeze well used may depend on the type ofrefrigeration system used to form a low temperature zone. The type ofrefrigeration system may be, but is not limited to, a batch operatedrefrigeration system, a circulated fluid refrigeration system, arefrigeration system that utilizes a vaporization cycle, a refrigerationsystem that utilizes an adsorption-desorption refrigeration cycle, or arefrigeration system that uses an absorption-desorption refrigerationcycle. Different types of refrigeration systems may be used at differenttimes during formation and/or maintenance of a low temperature zone. Insome embodiments, freeze wells may include casings. In some embodiments,freeze wells may include perforated casings or casings with other typesof openings. In some embodiments, a portion of a freeze well may be anopen wellbore.

[1692] A batch operated refrigeration system may utilize a plurality offreeze wells. A refrigerant is placed in the freeze wells. Heattransfers from the formation to the freeze wells. The refrigerant may bereplenished or replaced to maintain the freeze wells at desiredtemperatures.

[1693]FIG. 256 depicts an embodiment of batch operated freeze well 8012.Freeze well 8012 may include casing 8034, inlet conduit 8036, ventconduit 8038, and packing 8040. Packing 8040 may be formed near a top ofwhere a low temperature zone is to be formed in a formation. In someembodiments, packing is not utilized. Inlet conduit 8036 and/or ventconduit 8038 may extend through packing 8040. Refrigerant 8041 may beinserted into freeze well 8012 through inlet conduit 8036. Inlet conduit8036 may be insulated, or formed of an insulating material, to inhibitheat transfer to refrigerant 8041 as the refrigerant is transportedthrough the inlet conduit. In an embodiment, inlet conduit 8036 isformed of high density polyethylene. Vapor generated by heat transferbetween the formation and refrigerant 8041 may exit freeze well 8012through vent conduit 8038. In some embodiments, a vent conduit may notbe needed.

[1694] In some freeze well embodiments, a low temperature zone may beformed by batch operated freeze wells that do not include sealedcasings. Portions of freeze wells may be open wellbores, and/or portionsof the wellbores may include casings that have perforations or othertypes of openings. FIG. 257 depicts an embodiment of freeze well 8012that includes an open wellbore portion. To use freeze wells that includeopen wellbore portions and/or perforations or other types of openings,water may be introduced into the freeze wells to fill fractures and/orpore space within the formation adjacent to the wellbore. A pump may beused to remove excess water from the wellbore. In some embodiments,addition of water into the wellbore may not be necessary. Cryogenicrefrigerant 8041, such as liquid nitrogen, may be introduced into thewellbores to freeze material in the formation adjacent to the wellboresand seal any fractures or pore spaces of the formation that are adjacentto the freeze wells. Cryogenic refrigerant 8041 may be periodicallyreplenished so that a frozen barrier is formed and maintained.Alternately, a less cold, less expensive fluid, (such as a dry ice andlow freezing point liquid bath) may be substituted for the cryogenicrefrigerant after evaporation or removal of the cryogenic refrigerantfrom the wellbores. The less cold fluid may be used to form and/ormaintain the frozen barrier.

[1695] A need to replenish refrigerant may make the use of batchoperated freeze wells economical only for forming a low temperature zonearound a relatively small treatment area. The need to replenishrefrigerant may allow for economical operation of batch operated freezewells only for relatively short periods of time. Batch operated freezewells may advantageously be able to form a frozen barrier in a shortperiod of time, especially if a close freeze well spacing and acryogenic fluid is used. Batch operated freeze wells may be able to forma frozen barrier even when there is a large fluid flow rate adjacent tothe freeze wells. Batch operated freeze wells that use liquid nitrogenmay be able to form a frozen barrier when formation fluid flows at arate of up to about 20 m/day.

[1696] A circulated refrigeration system may utilize a plurality offreeze wells. A refrigerant may be circulated through the freeze wellsand through a refrigeration unit. The refrigeration unit may cool therefrigerant to an initial refrigerant temperature. The freeze wells maybe coupled together in series, parallel, or series and parallelcombinations. The circulated refrigeration system may be a high volumesystem. When the system is initially started, the temperature differencebetween refrigerant entering a refrigeration unit and leaving arefrigeration unit may be relatively large (e.g., from about 10° C. toabout 30° C.) and may quickly diminish. After formation of a frozenbarrier, the temperature difference may be 1° C. or less. It may bedesirable for the temperature of the circulated refrigerant to be verylow after the refrigerant passes through a refrigeration unit so thatthe refrigerant will be able to form a thick low temperature zoneadjacent to the freeze wells. An initial working temperature of therefrigerant may be −25° C., −40° C., −50° C., or lower.

[1697]FIG. 258 depicts an embodiment of a circulated refrigerant type ofrefrigeration system that may be used to form low temperature zone 8017around treatment area 8000. The refrigeration system may includerefrigeration units 8042, cold side conduit 8044, warm side conduit8046, and freeze wells 8012. Cold side conduits 8044 and warm sideconduits 8046 (as shown in FIG. 255) may be made of insulated polymerpiping such as HDPE (high-density polyethylene). Cold side conduits 8044and warm side conduits 8046 may couple refrigeration units 8042 tofreeze wells 8012 in series, parallel, or series and parallelarrangements. The type of piping arrangement used to connect freezewells 8012 to refrigeration units 8042 may depend on the type ofrefrigeration system, the number of refrigeration units, and the heatload required to be removed from the formation by the refrigerant.

[1698] In some embodiments, freeze wells 8012 may be connected torefrigeration conduits 8044, 8046 in a parallel configuration asdepicted in FIG. 258. Cold side conduit 8044 may transport refrigerantfrom a first storage tank of refrigeration unit 8042 to freeze wells8012. The refrigerant may travel through freeze wells 8012 to warm sideconduit 8046. Warm side conduit 8046 may transport the refrigerant to asecond storage tank of refrigeration unit 8042. Parallel configurationsfor refrigeration systems may be utilized when a low temperature zoneextends for a long length (e.g., 50 m or longer). Several refrigerationsystems may be needed to form a perimeter barrier around a treatmentarea.

[1699] In some embodiments, freeze wells may be connected torefrigeration conduits in parallel and series configurations. Two ormore freeze wells may be coupled together in a series piping arrangementto form a group. Each group may be coupled in a parallel pipingarrangement to the cold side conduit and the warm side conduit.

[1700] A circulated fluid refrigeration system may utilize a liquidrefrigerant that is circulated through freeze wells. A liquidcirculation system utilizes heat transfer between a circulated liquidand the formation without a significant portion of the refrigerantundergoing a phase change. The liquid may be any type of heat transferfluid able to function at cold temperatures. Some of the desiredproperties for a liquid refrigerant are: a low working temperature, lowviscosity, high specific heat capacity, high thermal conductivity, lowcorrosiveness, and low toxicity. A low working temperature of therefrigerant allows for formation of a large low temperature zone arounda freeze well. A low working temperature of the liquid should be about−20° C. or lower. Fluids having low working temperatures at or below−20° C. may include certain salt solutions (e.g., solutions containingcalcium chloride or lithium chloride). Other salt solutions may includesalts of certain organic acids (e.g., potassium formate, potassiumacetate, potassium citrate, ammonium formate, ammonium acetate, ammoniumcitrate, sodium citrate, sodium formate, sodium acetate). One liquidthat may be used as a refrigerant below −50° C. is Freezium®, availablefrom Kemira Chemicals (Helsinki, Finland). Another liquid refrigerant isa solution of ammonia and water with a weight percent of ammonia betweenabout 20% and about 40%.

[1701] A refrigerant that is capable of being chilled below a freezingtemperature of formation water may be used to form a low temperaturezone. The following equation (the Sanger equation) may be used to modelthe time t₁ needed to form a frozen barrier of radius R around a freezewell having a surface temperature of T_(s): $\begin{matrix}{{t_{1} = {\frac{R^{2}L_{1}}{4k_{f}v_{s}}( {{2\quad \ln \quad \frac{R}{r_{o}}} - 1 + \frac{c_{vf}v_{s}}{L_{1}}} )}}{{{in}\quad {{which}:\text{}L_{1}}} = {L\quad \frac{a_{r}^{2} - 1}{2\quad \ln \quad a_{r}}c_{vu}v_{o}}}{a_{r} = {\frac{R_{A}}{R}\quad.}}} & (59)\end{matrix}$

[1702] In these equations, k_(f) is the thermal conductivity of thefrozen material; c_(vf) and c_(vu) are the volumetric heat capacity ofthe frozen and unfrozen material, respectively; r_(o) is the radius ofthe freeze well; v_(s) is the temperature difference between the freezewell surface temperature T_(s) and the freezing point of water T_(o);v_(o) is the temperature difference between the ambient groundtemperature T_(g) and the freezing point of water T_(o); L is thevolumetric latent heat of freezing of the formation; R is the radius atthe frozen-unfrozen interface; and R_(A) is a radius at which there isno influence from the refrigeration pipe. The temperature of therefrigerant is an adjustable variable that may significantly affect thespacing between refrigeration pipes.

[1703]FIG. 259 shows simulation results as a plot of time to reduce atemperature midway between two freeze wells to 0° C. versus well spacingusing refrigerant at an initial temperature of −50° C. and usingrefrigerant at an initial temperature of −25° C. The formation beingcooled in the simulation was 83.3 liters of liquid oil/metric ton GreenRiver oil shale. The results for the −50° C. temperature refrigerant aredenoted by reference numeral 8048. The results for the −25° C.temperature refrigerant are denoted by reference numeral 8050. Thisfigure shows that reducing refrigerant temperature will reduce the timeneeded to form an interconnected low temperature zone sufficiently coldto freeze formation water. For example, reducing the initial refrigeranttemperature from −25° C. to −50° C. may halve the time needed to form aninterconnected low temperature zone for a given spacing between freezewells.

[1704] In certain circumstances (e.g., where hydrocarbon containingportions of a formation are deeper than about 300 m), it may bedesirable to minimize the number of freeze wells (i.e., increase freezewell spacing) to improve project economics. Using a refrigerant that cango to low temperatures allows for the use of a large freeze wellspacing.

[1705] EQN. 59 implies that a large low temperature zone may be formedby using a refrigerant having an initial temperature that is very low.To form a low temperature zone for in situ conversion processes forformations, the use of a refrigerant having an initial cold temperatureof about −50° C. or lower may be desirable. Refrigerants having initialtemperatures warmer than about −50° C. may also be used, but suchrefrigerants may require longer times for the low temperature zonesproduced by individual freeze wells to connect. In addition, suchrefrigerants may require the use of closer freeze well spacings and/ormore freeze wells.

[1706] A refrigeration unit may be used to reduce the temperature of arefrigerant liquid to a low working temperature. In some embodiments,the refrigeration unit may utilize an ammonia vaporization cycle.Refrigeration units are available from Cool Man Inc. (Milwaukee, Wis.),Gartner Refrigeration & Manufacturing (Minneapolis, Minn.), and othersuppliers. In some embodiments, a cascading refrigeration system may beutilized with a first stage of ammonia and a second stage of carbondioxide. The circulating refrigerant through the freeze wells may be 30weight % ammonia in water (aqua ammonia).

[1707] In some embodiments, refrigeration units for chilling refrigerantmay utilize an absorption-desorption cycle. An absorption refrigerationunit may produce temperatures down to about −60° C. using thermalenergy. Thermal energy sources used in the desorption unit of theabsorption refrigeration unit may include, but are not limited to, hotwater, steam, formation fluid, and/or exhaust gas. In some embodiments,ammonia is used as the refrigerant and water as the absorbent in theabsorption refrigeration unit. Absorption refrigeration units areavailable from Stork Thermeq B.V. (Hengelo, The Netherlands).

[1708] A vaporization cycle refrigeration system may be used to formand/or maintain a low temperature zone. A liquid refrigerant may beintroduced into a plurality of wells. The refrigerant may absorb heatfrom the formation and vaporize. The vaporized refrigerant may becirculated to a refrigeration unit that compresses the refrigerant to aliquid and reintroduces the refrigerant into the freeze wells. Therefrigerant may be, but is not limited to, ammonia, carbon dioxide, or alow molecular weight hydrocarbon (e.g., propane). After vaporization,the fluid may be recompressed to a liquid in a refrigeration unit orrefrigeration units and circulated back into the freeze wells. The useof a circulated refrigerant system may allow economical formation and/ormaintenance of a long low temperature zone that surrounds a largetreatment area. The use of a vaporization cycle refrigeration system mayrequire a high pressure piping system.

[1709]FIG. 260 depicts an embodiment of freeze well 8012. Freeze well8012 may include casing 8034, inlet conduit 8036, spacers 8052, andwellcap 8051. Spacers 8052 may position inlet conduit 8036 within casing8034 so that an annular space is formed between the casing and theconduit. Spacers 8052 may promote turbulent flow of refrigerant in theannular space between inlet conduit 8036 and casing 8034, but thespacers may also cause a significant fluid pressure drop. Turbulentfluid flow in the annular space may be promoted by roughening the innersurface of casing 8034, by roughening the outer surface of inlet conduit8036, and/or by having a small cross-sectional area annular space thatallows for high refrigerant velocity in the annular space. In someembodiments, spacers are not used.

[1710] Refrigerant may flow through cold conduit 8044 from arefrigeration unit to inlet conduit 8036 of freeze well 8012. Therefrigerant may flow through an annular space between inlet conduit 8036and casing 8034 to warm side conduit 8046. Heat may transfer from theformation to casing 8034 and from the casing to the refrigerant in theannular space. Inlet conduit 8036 may be insulated to inhibit heattransfer to the refrigerant during passage of the refrigerant intofreeze well 8012. In an embodiment, inlet conduit 8036 is a high densitypolyethylene tube. In other embodiments, inlet conduit 8036 is aninsulated metal tube.

[1711]FIG. 261 depicts an embodiment of circulated refrigerant freezewell 8012. Refrigerant may flow through U-shaped conduit 8054 that issuspended or packed in casing 8034. Suspending conduit 8054 in casing8034 may advantageously provide thermal contraction and expansion roomfor the conduit. In some embodiments, spacers may be positioned atselected locations along the length of the conduit to inhibit conduit8054 from contacting casing 8034. Typically, preventing conduit 8054from contacting casing 8034 is not needed, so spacers are not used.Casing 8034 may be filled with a low freezing point heat transfer fluidto enhance thermal contact and promote heat transfer between theformation, casing, and conduit 8054. In some embodiments, water or otherfluid that will solidify when refrigerant flows through conduit 8054 maybe placed in casing 8034. The solid formed in casing 8034 may enhanceheat transfer between the formation, casing, and refrigerant withinconduit 8054. Portions of conduit 8054 adjacent to the formation thatare not to be cooled may be formed of an insulating material (e.g., highdensity polyethylene) and/or the conduit portions may be insulated.Portions of conduit 8054 adjacent to the formation that are to be cooledmay be formed of a thermally conductive metal (e.g., copper or a copperalloy) to enhance heat transfer between the formation and refrigerantwithin the conduit portion.

[1712] In some freeze well embodiments, U-shaped conduits may besuspended or packed in open wellbores or in perforated casings insteadof in sealed casings. FIG. 262 depicts an embodiment of freeze well 8012having an open wellbore portion. Open wellbores and/or perforatedcasings may be used when water or other fluid is to be introduced intothe formation from the freeze wells. Water may be introduced into theformation to promote formation of a frozen barrier. Water may beintroduced into the formation through freeze wells during cleanupprocedures after completion of an in situ conversion process (e.g., thefreeze wells may be thawed and perforated for introduction of water). Insome embodiments, open wellbores and/or perforated casings may be usedwhen the freeze wells will later be converted to heat sources,production wells, and/or injection wells.

[1713] As depicted in FIG. 262, outlet leg 8056 of U-shaped conduit 8054may be wrapped around inlet leg 8058 adjacent to a portion of theformation that is to be cooled. Wrapping outlet leg 8056 around inletleg 8058 may significantly increase the heat transfer surface area ofconduit 8054. Inlet leg and outlet leg adjacent to portions of theformation that are not to be cooled may be insulated and/or made of aninsulating material. Conduits with an outlet leg wrapped around an inletleg are available from Packless Hose, Inc. (Waco, Tex.).

[1714] A time needed to form a low temperature zone may be dependent ona number of factors and variables. Such factors and variables mayinclude, but are not limited to, freeze well spacing, refrigeranttemperature, length of the low temperature zone, fluid flow rate intothe treatment area, salinity of the fluid flowing into the treatmentarea, and the refrigeration system type, or refrigerant used to form thebarrier. The time needed to form the low temperature zone may range fromabout two days to more than a year depending on the extent and spacingof the freeze wells. In some embodiments, a time needed to form a lowtemperature zone may be about 6 to 8 months.

[1715] Spacing between adjacent freeze wells may be a function of anumber of different factors. The factors may include, but are notlimited to, physical properties of formation material, type ofrefrigeration system, type of refrigerant, flow rate of material into orout of a treatment area defined by the freeze wells, time for formingthe low temperature zone, and economic considerations. Consolidated orpartially consolidated formation material may allow for a largeseparation distance between freeze wells. A separation distance betweenfreeze wells in consolidated or partially consolidated formationmaterial may be from about 3 m to 10 m or larger. In an embodiment, thespacing between adjacent freeze wells is about 5 m. Spacing betweenfreeze wells in unconsolidated or substantially unconsolidated formationmaterial may need to be smaller than spacing in consolidated formationmaterial. A separation distance between freeze wells in unconsolidatedmaterial may be 1 m or more.

[1716] Numerical simulations may be used to determine spacing for freezewells based on known physical properties of the formation. A generalpurpose simulator, such as the Steam, Thermal and Advanced ProcessesReservoir Simulator (STARS), may be used for numerical simulation work.Also, a simulator for freeze wells, such as TEMP W available fromGeoslope (Calgary, Alberta), may be used for numerical simulations. Thenumerical simulations may include the effect of heat sources operatingwithin a treatment area defined by the freeze wells.

[1717] A time needed to form a frozen barrier may be determined bycompleting a thermal analysis using a finite element model. FIG. 263depicts results of a simulation using TEMP W for 83.3 liters of liquidoil/metric ton of Green River oil shale presented as temperature versustime for a formation cooled with a refrigerant that has an initialworking temperature of −50° C. Curve 8060 depicts a representation of atemperature of an outer wall of a freeze well casing. Curve 8062 depictsa temperature midway between two freeze wells that are separated byabout 7.6 m. Curve 8064 depicts temperature midway between two freezewells that are separated by about 6.1 m. Curve 8066 depicts temperaturemidway between two freeze wells that are separated by about 4.6 m.

[1718]FIG. 263 illustrates that closer freeze well spacing decreases anamount of time required to form an interconnected low temperature zonecapable of freezing formation water. The freeze well casing temperaturedecreased from about 14° C. to less than −40° C. in less than 200 days.In the same time frame, a temperature at a midpoint between two freezewells with a 4.6 m spacing decreased from about 14° C. to −5° C. As thespacing between the freeze wells increased, the time needed to reduce atemperature at a midpoint between two freeze wells also increased. Theplot indicates that shorter distances between adjacent freeze wells maydecrease the time necessary to form an interconnected low temperaturezone. The freeze wells in the simulation are similar to the freeze wellsdepicted in FIG. 260.

[1719] The use of a specific type of refrigerant may be made based on anumber of different factors. Such factors may include, but are notlimited to, the type of refrigeration system employed, the chemicalproperties of the refrigerant, and the physical properties of therefrigerant.

[1720] Refrigerants may have different equipment requirements. Forexample, cryogenic refrigerants (e.g., liquid nitrogen) may inducegreater temperature differentials than a brine solution. A required flowrate for a circulated cryogenic refrigerant system may be substantiallylower than a required flow rate for a brine solution refrigerant toachieve a desired temperature in a formation. A required volume ofcryogenic refrigerant for a batch refrigeration system may be large. Theuse of a cryogenic refrigerant may result in significant equipmentsavings, but the cost of reducing refrigerant to cryogenic temperaturesmay make the use of a cryogenic refrigeration system uneconomical.

[1721] Fluid flow into a treatment area may inhibit formation of afrozen barrier. Formations having high permeability may have high fluidflow rates that inhibit formation of a frozen barrier. Fluid flow ratemay limit a residence time of a fluid in a low temperature zone around afreeze well. If fluid is flowing rapidly adjacent to a freeze well, aresidence time of the fluid proximate the freeze well may beinsufficient to allow the fluid to freeze in a cylindrical patternaround the freeze well. Fluid flow rate may influence the shape of abarrier formed around freeze wells. A high flow rate may result inirregular low temperature zones around freeze wells. FIG. 264 depictsshapes of low temperature zones 8017 around freeze wells 8012 whenformation water flows by the freeze wells at a rate that allows forformation of frozen perimeter barrier 8002. Direction of formation waterflow is indicated by arrows 8073. As time passes, the frozen barrier mayexpand outwards from the freeze wells. If the formation water flow rateis high enough, the fluid may inhibit overlap of low temperature zones8017 between adjacent wells, as depicted in FIG. 265. In such asituation, formation fluid would continue to flow into a treatment areaand formation of a frozen barrier would be inhibited. To alleviate theproblem of non-closure of the low temperature zone, additional freezewells may be installed between the existing freeze wells, dewateringwells may be used to reduce formation fluid flow rate by the freezewells to allow for formation of an interconnected low temperature zone,or other techniques may be used to reduce formation fluid flow to a ratethat will allow low temperature zones from adjacent wells tointerconnect so that a frozen barrier forms.

[1722] In some embodiments, fluid flow into a treatment area may beinhibited to allow formation of a frozen barrier by freeze wells. In anembodiment, dewatering wells may be placed in the formation to inhibitfluid flow past freeze wells during formation of a frozen barrier. Thedewatering wells may be placed far enough away from the freeze wells sothat the dewatering wells do not create a flow rate past the freezewells that inhibits formation of a frozen barrier. In some embodiments,injection wells may be used to inject fluid into the formation so thatfluid flow by the freeze wells is reduced to a level that will allow forformation of interconnected frozen barriers between adjacent freezewells.

[1723] In an embodiment, freeze wells may be positioned between an innerrow and an outer row of dewatering wells. The inner row of dewateringwells and the outer row of dewatering wells may be operated to have aminimal pressure differential so that fluid flow between the inner rowof dewatering wells and the outer row of dewatering wells is minimized.The dewatering wells may remove formation water between the outerdewatering row and the inner dewatering row. The freeze wells may beinitialized after removal of formation water by the dewatering wells.The freeze wells may cool the formation between the inner row and theouter row to form a low temperature zone. The power supplied to thedewatering wells may be reduced stepwise after the freeze wells form aninterconnected low temperature zone that is able to solidify formationwater. Reduction of power to the dewatering wells may allow some waterto enter the low temperature zone. The water may freeze to form a frozenbarrier. Operation of the dewatering wells may be ended when the frozenbarrier is fully formed.

[1724] In some formations, a combination batch refrigeration system andcirculated fluid refrigeration system may be used to form a frozenbarrier when fluid flow into the formation is too high to allowformation of the frozen barrier using only the circulated refrigerationsystem. Batch freeze wells may be placed in the formation and operatedwith cryogenic refrigerant to form an initial frozen barrier thatinhibits or stops fluid flow towards freeze wells of a circulated fluidrefrigeration system. Circulation freeze wells may be placed on a sideof the batch freeze wells towards a treatment area. The batch freezewells may be operated to form a perimeter barrier that stops or reducesfluid flow to the circulation freeze wells. The circulation freeze wellsmay be operated to form a primary perimeter barrier. After formation ofthe primary frozen barrier, use of the batch freeze wells may bediscontinued. Alternately, some or all of the batch operated freezewells may be converted to circulation freeze wells that maintain and/orexpand the initial barrier formed by the batch freeze wells. Convertingsome or all of the batch freeze wells to circulation freeze wells mayallow a thick frozen barrier to be formed and maintained around atreatment area. In some embodiments, a combination of dewatering wellsand batch operated freeze wells may be used to reduce fluid flow pastcirculation freeze wells so that the circulation freeze wells form afrozen barrier.

[1725] Open wellbore freeze wells may be utilized in some formationsthat have very low permeability. Freeze well wellbores may be formed insuch formations. A frozen barrier may initially be formed using a verycold fluid, such as liquid nitrogen, that is placed in casings of thefreeze wells. After the very cold fluid forms an interconnected frozenbarrier around the treatment area, the very cold cryogenic fluid may bereplaced with a circulated refrigerant that will maintain the frozenbarrier during in situ processing of the formation. For example, liquidnitrogen at a temperature of about −196° C. may be used to form aninterconnected frozen barrier around a treatment area by placing theliquid nitrogen within the freeze wells and replenishing the liquidnitrogen when necessary. The liquid nitrogen may be placed in an annularspace between an inlet line and a casing in each freeze well. After theliquid nitrogen forms an interconnected frozen barrier between adjacentfreeze wells, the liquid nitrogen may be removed from the freeze wells.A fluid, such as a low freezing point alcohol, may be circulated intoand out of the freeze wells to raise the temperature adjacent to thefreeze wells. When the temperature of the well casing is sufficientlyhigh to inhibit refrigerant, such as a brine solution, from solidifyingin the freeze wells, the fluid may be replaced with the refrigerant. Therefrigerant may be used to maintain the frozen barrier.

[1726]FIG. 244 depicts freeze wells 8012 installed around treatmentareas 8000. ICP wells 8004 may be installed in treatment areas 8000prior to, simultaneously with, or after insertion of freeze wells 8012.In some embodiments, wellbores for ICP wells 8004 and/or freeze wells8012 may be drilled into a formation. In other embodiments, wellboresmay be formed when the wells are vibrationally inserted and/or driveninto the formation. In some embodiments, well casings are formed of pipesegments. Connections between lengths of pipe may be self-sealingtapered threaded connections, and/or welded joints. In otherembodiments, well casings may be inserted using coiled tubinginstallation. Integrity of coiled tubing may be tested beforeinstallation by hydrotesting at pressure.

[1727] Coiled tubing installation may reduce a number of welded and/orthreaded connections in a length of casing. Welds and/or threadedconnections in coiled tubing may be pre-tested for integrity (e.g., byhydraulic pressure testing). Coiled tubing may be installed more easilyand faster than installation of pipe segments joined together bythreaded and/or welded connections.

[1728] Embodiments of heat sources, production wells, and/or freezewells may be installed in a formation using coiled tubing installation.Some embodiments of heat sources, production wells, and freeze wellsinclude an element placed within an outer casing. For example, aconductor-in-conduit heater may include an outer casing with a conduitdisposed in the casing. A production well may include a heater elementor heater elements disposed within a casing. A freeze well may include arefrigerant inlet conduit disposed within a casing, or a U-shapedconduit disposed in a casing. Spacers may be spaced along a length of anelement, or elements, positioned within a casing to inhibit the element,or elements, from contacting the casing walls.

[1729] In some embodiments of heat sources, production wells, and freezewells, casings may be installed using coiled tube installation. Elementsmay be placed within the casing after the casing is placed in theformation for heat sources or wells that include elements within thecasings. In some embodiments, sections of casings may be threaded and/orwelded and inserted into a wellbore using a drilling rig. In someembodiments, elements may be placed within the casing before the casingis wound onto a reel. The elements within a casing are installed in aformation when the casing is installed in the formation. For example, acoiled tubing reel for forming a freeze well such as the freeze welldepicted in FIG. 260 may include 8.9 cm (3.5 in.) outer diameter carbonsteel coiled tubing with 5.1 cm (2 in.) outer diameter high densitypolyethylene tubing positioned inside the carbon steel tubing. Duringinstallation, a portion of the polyethylene tubing may be cut so thatthe polyethylene tubing will be recessed within the steel casing. Awellcap may be threaded and/or welded to the steel tubing to seal theend of the tubing. The coiled tubing may be inserted by a coiled tubingunit into the formation.

[1730] Care may be taken during design and installation of freeze wellcasing strings to allow for thermal contraction of the casing stringwhen refrigerant passes through the casing. Allowance for thermalcontraction may inhibit the development of stress fractures and leaks inthe casing. If a freeze well casing were to leak, leaking refrigerantmay inhibit formation of a frozen barrier or degrade an existing frozenbarrier. Water or other diluent may be used to flush the formation todiffuse released refrigerant if a leak occurs.

[1731] Diameters of freeze well casings installed in a formation may beoversized as compared to a minimum diameter needed to allow forformation of a low temperature zone. For example, if design calculationsindicate that 10.2 cm (4 in.) piping is needed to provide sufficientheat transfer area between the formation and the freeze wells, 15.2 cm(6 in.) piping may be placed in the formation. The oversized casing mayallow a sleeve or other type of seal to be placed into the casing shoulda leak develop in the freeze well casing.

[1732] In some embodiments, flow meters may be used to monitor for leaksof refrigerant within freeze wells. A first flow meter may measure anamount of refrigerant flow into a freeze well or a group of wells. Asecond flow meter may measure an amount of flow out of a freeze well ora group of freeze wells. A significant difference between themeasurements taken by the first flow meter and the second flow meter mayindicate a leak in the freeze well or in a freeze well of the group offreeze wells. A significant difference between the measurements mayresult in the activation of a solenoid valve that inhibits refrigerantflow to the freeze well or group of freeze wells.

[1733] Freeze well placement may vary depending on a number of factors.The factors may include, but are not limited to, predominant directionof fluid flow within the formation; type of refrigeration system used;spacing of freeze wells; and characteristics of the formation such asdepth, length, thickness, and dip. Placement of freeze wells may alsovary across a formation to account for variations in geological strata.In some embodiments, freeze wells may be inserted into hydrocarboncontaining portions of a formation. In some embodiments, freeze wellsmay be placed near hydrocarbon containing portions of a formation. Insome embodiments, some freeze wells may be positioned in hydrocarboncontaining portions while other freeze wells are placed proximate thehydrocarbon containing portions. Placement of heat sources, dewateringwells, and/or production wells may also vary depending on the factorsaffecting freeze well placement.

[1734] ICP wells may be placed a large distance away from freeze wellsused to form a low temperature zone around a treatment area. In someembodiments, ICP wells may be positioned far enough away from freezewells so that a temperature of a portion of formation between the freezewells and the ICP wells is not influenced by the freeze wells or the ICPwells when the freeze wells have formed an interconnected frozen barrierand ICP wells have raised temperatures throughout a treatment area topyrolysis temperatures. In some embodiments, ICP wells may be placed 20m, 30 m, or farther away from freeze wells used to form a lowtemperature zone.

[1735] In some embodiments, ICP wells may be placed in a relativelyclose proximity to freeze wells. During in situ conversion, a hot zoneestablished by heat sources and a cold zone established by freeze wellsmay reach an equilibrium condition where the hot zone and the cold zonedo not expand towards each other. FIG. 266 depicts thermal simulationresults after 1000 days when heat source 8022 at about 650° C. is placedat a center of a ring of freeze wells 8012 that are about 9.1 m awayfrom the heat source and spaced at about 2.4 m intervals. The freezewells are able to maintain frozen barrier 8002 that extends over 1 minwards towards the heat source. On an outer side of the freeze wells,the freeze barrier is much thicker, and the freeze wells influenceportions (e.g., low temperature zone 8017) of the formation up to about15 m away from the freeze wells.

[1736] Thermal diffusivities and other properties of both saturatedfrozen formation material and hot, dry formation material may allowoperation of heat sources close to freeze wells. These properties mayinhibit the heat provided by the heat sources from breaking through afrozen barrier established by the freeze wells. Frozen saturatedformation material may have a significantly higher thermal diffusivitythan hot, dry formation material. The difference in the thermaldiffusivity of hot, dry formation material and cold, saturated formationmaterial predicts that a cold zone will propagate faster than a hotzone. Fast propagation of a cold zone established and maintained byfreeze wells may inhibit a hot zone formed by heat sources from meltingthrough the cold zone during thermal treatment of a treatment area.

[1737] In some embodiments, a heat source may be placed relatively closeto a frozen barrier formed and maintained by freeze wells without theheat source being able to break through the frozen barrier. Although aheat source may be placed close to a frozen barrier, heat sources aretypically placed 5 m or farther away from a frozen barrier formed andmaintained by freeze wells. In an embodiment, heat sources are placedabout 30 m away from freeze wells. Since the heat sources may be placedrelatively close to the frozen barrier, a relatively large section of aformation may be treated without an excessive number of freeze wells. Anumber of freeze wells needed to surround an area increases at asignificantly lower rate than the number of ICP wells needed tothermally treat the surrounded area as the size of the surrounded areaincreases. This is because the surface-to-volume ratio decreases withthe radius of a treated volume.

[1738] Measurable properties and/or testing procedures may indicateformation of a frozen barrier. For example, if dewatering is takingplace on an inner side of freeze wells, the amount of water removed fromthe formation through dewatering wells may significantly decrease as afrozen barrier forms and blocks recharge of water into a treatment area.

[1739] A treatment area may be saturated with formation water. When afrozen perimeter barrier is formed around the treatment area, waterrecharge and removal from the treatment area is stopped. The frozenperimeter barrier may continue to expand. Expansion of the perimeterbarrier may cause the hydrostatic head (i.e., piezometric head) in thetreatment area to rise as compared to the hydrostatic head of formationoutside of the frozen barrier. The hydrostatic head in the barrier mayrise because the water in the formation is confined in an increasinglysmaller volume as the frozen barrier expands inwards. The hydrostaticchange may be relatively small, but still measurable. Piezometers placedinside and outside of a ring of freeze wells may be used to determinewhen a frozen barrier is formed based on hydrostatic head measurements.

[1740] In addition, transient pressure testing (e.g., drawdown tests orinjection tests) in the treatment area may indicate formation of afrozen barrier. Such transient pressure tests may also indicate thepermeability at the barrier. Pressure testing is described in PressureBuildup and Flow Tests in Wells by C. S. Matthews & D. G. Russell (SPEMonograph, 1967).

[1741] A transient fluid pulse test may be used to determine or confirmformation of a perimeter barrier. A treatment area may be saturated withformation water after formation of a perimeter barrier. A pulse may beinstigated inside a treatment area surrounded by the perimeter barrier.The pulse may be a pressure pulse that is produced by pumping fluid(e.g., water) into or out of a wellbore. In some embodiments, thepressure pulse may be applied in incremental steps, and responses may bemonitored after each step. After the pressure pulse is applied, thetransient response to the pulse may be measured by, for example,measuring pressures at monitor wells and/or in the well in which thepressure pulse was applied. Monitoring wells used to detect pressurepulses may be located outside and/or inside of the treatment area.

[1742] In some embodiments, a pressure pulse may be applied by drawing avacuum on the formation through a wellbore. If a frozen barrier isformed, a portion of the pulse will be reflected by the frozen barrierback towards the source of the pulse. Sensors may be used to measureresponse to the pulse. In some embodiments, a pulse or pulses areinstigated before freeze wells are initialized. Response to the pulsesis measured to provide a base line for future responses. After formationof a perimeter barrier, a pressure pulse initiated inside of theperimeter barrier should not be detected by monitor wells outside of theperimeter barrier. Reflections of the pressure pulse measured within thetreatment area may be analyzed to provide information on theestablishment, thickness, depth, and other characteristics of the frozenbarrier.

[1743] In certain embodiments, hydrostatic pressures will tend to changedue to natural forces (e.g., tides, water recharge, etc.). A sensitivepiezometer (e.g., a quartz crystal sensor) may be able to accuratelymonitor natural hydrostatic pressure changes. Fluctuations in naturalhydrostatic pressure changes may indicate formation of a frozen barrieraround a treatment area. For example, if areas surrounding the treatmentarea undergo natural hydrostatic pressure changes but the area enclosedby the frozen barrier does not, this is an indication of formation ofthe frozen barrier.

[1744] In some embodiments, a tracer test may be used to determine orconfirm formation of a frozen barrier. A tracer fluid may be injected ona first side of a perimeter barrier. Monitor wells on a second side ofthe perimeter barrier may be operated to detect the tracer fluid. Nodetection of the tracer fluid by the monitor wells may indicate that theperimeter barrier is formed. The tracer fluid may be, but is not limitedto, carbon dioxide, argon, nitrogen, and isotope labeled water orcombinations thereof. A gas tracer test may have limited use insaturated formations because the tracer fluid may not be able to traveleasily from an injection well to a monitor well through a saturatedformation. In a water saturated formation, an isotope labeled water(e.g., deuterated or tritiated water) or a specific ion dissolved inwater (e.g., thiocyanate ion) may be used as a tracer fluid.

[1745] If tests indicate that a frozen perimeter barrier has not beenformed by the freeze wells, the location of incomplete sections of theperimeter barrier may be determined. Pulse tests may indicate thelocation of unformed portions of a perimeter barrier. Tracer tests mayindicate the general direction in which there is an incomplete sectionof perimeter barrier.

[1746] Temperatures of freeze wells may be monitored to determine thelocation of an incomplete portion of a perimeter barrier around atreatment area. In some freeze well embodiments, such as in theembodiment depicted in FIG. 260 and FIG. 255, freeze well 8012 mayinclude port 8074. Temperature probes, such as resistance temperaturedevices, may be inserted into port 8074. Refrigerant flow to the freezewells may be stopped. Dewatering wells may be operated to draw fluidpast the perimeter barrier. The temperature probes may be moved withinports 8074 to monitor temperature changes along lengths of the freezewells. The temperature may rise quickly adjacent to areas where a frozenbarrier has not formed. After the location of the portion of perimeterbarrier that is unformed is located, refrigerant flow through freezewells adjacent to the area may be increased and/or an additional freezewell may be installed near the area to allow for completion of a frozenbarrier around the treatment area.

[1747] A typical oil shale formation treated by a thermal treatmentprocess may have a thick overburden. Average thickness of an overburdenmay be greater than about 20 m, 50 m, or 500 m. The overburden mayprovide a substantially impermeable barrier that inhibits vapor releaseto the atmosphere. ICP wells passing into the formation may include wellcompletions that cement or otherwise seal well casings from surroundingformation material so that formation fluid cannot pass to the atmosphereadjacent to the wells.

[1748] In some embodiments of an in situ conversion process, heatsources may be placed in a hydrocarbon containing portion of theformation such that the heat sources do not heat sections of thehydrocarbon containing portion nearest to the ground surface topyrolysis temperatures. The heat sources may heat a section of thehydrocarbon containing portion that is below the untreated section topyrolysis temperatures. The untreated section of hydrocarbon containingmaterial may be considered to be part of the overburden.

[1749] Some formations may have relatively thin overburdens over aportion of the formation. Some formations may have an outcrop thatapproaches or extends to ground surface. In some formations, anoverburden may have fractures or develop fractures during thermalprocessing that connect or approach the ground surface. Some formationsmay have permeable portions that allow formation fluid to escape to theatmosphere when the formation is heated. A ground cover may be providedfor a portion of a formation that will allow, or potentially allow,formation fluid to escape to the atmosphere during thermal processing.

[1750] A ground cover may include several layers. FIG. 267 depicts anembodiment of ground cover 8076. Ground cover 8076 may include fillmaterial 8078 used to level a surface on which the ground cover isplaced, first impermeable layer 8080, insulation 8082, framework 8084,and second impermeable layer 8086. Other embodiments of ground coversmay include a different number of layers. For example, a ground covermay only include a first impermeable layer. In some embodiments, firstimpermeable layer 8080 may be formed of concrete, metal, plastic, clay,or other types of material that inhibit formation fluid from passingfrom the ground to the atmosphere.

[1751] Ground cover 8076 may be sealed to the ground, to ICP wells, tofreeze wells, and to other equipment that passes through the groundcover. Ground cover 8076 may inhibit release of formation fluid to theatmosphere. Ground cover 8076 may also inhibit rain and run-off waterseepage into a treatment area from the ground surface. The choice ofground cover material may be based on temperatures and chemicals towhich ground cover 8076 is subjected. In embodiments in which overburden540 is sufficiently thick so that temperatures at the ground surface arenot influenced, or are only slightly elevated, by heating of theformation, ground cover 8076 may be a polymer sheet. For thinneroverburdens 540, where heating the formation may significantly influencethe temperature at ground surface, ground cover 8076 may be formed ofmetal sheet placed over the treatment area. Ground cover 8076 may beplaced on a graded surface, and wellbores for ICP wells and freeze wellsmay be placed into the formation through the ground cover. Ground cover8076 may be welded or otherwise sealed to well casings and/or otherstructures extending through the ground cover. If needed, insulation8082 may be placed above or below ground cover 8076 to inhibit heat lossto the atmosphere.

[1752] Ground cover 8076 may include framework 8084. In certainembodiments, framework 8084 supports a portion of ground cover 8076. Forexample, framework 8084 may support second impermeable layer 8086, whichmay be a rain cover that extends over a portion or all of the treatmentarea. In other embodiments, framework 8084 supports well casings,walkways, and/or other structures that provide access to wells withinthe treatment area, so that personnel do not have to contact groundcover 8076 when accessing a well or equipment within the treatment area.

[1753] Perforated piping of a piping system may be placed in the groundor adjacent to the ground surface below a ground cover. The perforatedpiping may provide a path for transporting formation fluid passingthrough the formation towards the surface to surface facilities. Inother embodiments, a piping system may be connected to openings thatpass through the ground cover. Blowers or other types of drive systemsmay draw formation fluid adjacent to the ground cover into the piping.Monitor wells may be placed through a ground cover at the groundsurface. If the monitor wells detect formation fluid, the drive systemmay be activated to transport the fluid to a surface facility.

[1754] Ground cover 8076 may be sealed to the ground. In an embodimentof an in situ conversion process, freeze wells 8012 are used to form alow temperature zone around the treatment area. A portion of therefrigerant capacity utilized in freeze wells 8012 may be used to freezea portion of the formation adjacent to the ground surface. Ground cover8076 may include a lip that is pushed into wet ground prior to formationof the low temperature zone. When the low temperature zone is formed,the freeze wells may freeze the ground and the ground cover together.Insulation may be placed over the frozen ground to inhibit heatabsorption from the atmosphere. In other embodiments, a ground cover maybe welded or otherwise sealed to a sheet barrier or a grout wall formedin the formation around the treatment area.

[1755] In some embodiments, an upper layer of a formation (e.g., anoutcrop) that allows, or potentially allows, formation fluid to escapeto the atmosphere during thermal treatment is excavated. The depth ofthe excavation opening created may be about ⅓ m, 1 m, 5 m, 10 m, orgreater. Perforated piping of a piping system may be placed in theexcavation and covered with a permeable layer such as sand and/orgravel. A concrete, clay, or other impermeable layer may be formed as acover over the excavation opening. Alternately, a similar structure maybe built on top of the ground to form an impermeable cover over aportion of a formation. The concrete, clay, or other impermeable layermay function as an artificial overburden.

[1756] A treatment area may be subjected to various processessequentially. Treatment areas may undergo many different processesincluding, but not limited to, initial heating, production ofhydrocarbons, pyrolysis, synthesis gas generation, storage of fluids,sequestration, remediation, use as a filtration unit, solution mining,and/or upgrading of hydrocarbon containing feed streams. Fluids may bestored in a formation as long term storage and/or as temporary storageduring unusual situations such as a power failure or surface facilitiesshutdown. Various factors may be used to determine which processes willbe used in particular treatment areas. Factors determining the use of aformation may include, but are not limited to, formation characteristicssuch as type, size, hydrology, and location; economic viability of aprocess; available market for products produced from the formation;available surface facilities to process fluid removed from theformation; and/or feedstocks for introduction into a formation toproduce desired products.

[1757] For some processes, a low temperature zone may be used to isolatea treatment area. A treatment area surrounded by a low temperature zonemay be used, in certain embodiments, as a storage area for fluidsproduced or needed on site. Fluids may be diverted from other areas ofthe formation in the event of an emergency. Alternatively, fluids may bestored in a treatment area for later use. A low temperature zone mayinhibit flow of stored fluids from a treatment area depending oncharacteristics of the stored fluids. A frozen barrier zone may benecessary to inhibit flow of certain stored fluids from a treatmentarea. Other processes which may benefit from an isolated treatment zonemay include, but are not limited to, synthesis gas generation, upgradingof hydrocarbon containing feed streams, filtration of feed stocks,and/or solution mining.

[1758] In some in situ conversion process embodiments, three or moresets of wells may surround a treatment area. FIG. 270 depicts a wellpattern embodiment for an in situ conversion process. Treatment area8000 may include a plurality of heat sources and/or production wells.Treatment area 8000 may be surrounded by a first set of freeze wells8028. The first set of freeze wells 8028 may establish a frozen barrierthat inhibits migration of fluid out of treatment area 8000 during thein situ conversion process.

[1759] The first set of freeze wells 8028 may be surrounded by a set ofmonitor and/or injection wells 8088. Monitor and/or injection wells 8088may be used during the in situ conversion process to monitor temperatureand monitor for the presence of formation fluid (e.g., for water, steam,hydrocarbons, etc.). If hydrocarbons or steam are detected, a breach ofthe frozen barrier established by the first set of freeze wells 8028 maybe indicated. Measures may be taken to determine the location of thebreach in the frozen barrier. After determining the location of thebreach, measures may be taken to stop the breach. In an embodiment, anadditional freeze well or freeze wells may be inserted into theformation between the first set of freeze wells and the set of monitorand/or injection wells 8088 to seal the breach.

[1760] The set of monitor and/or injection wells 8088 may be surroundedby a second set of freeze wells 8029. The second set of freeze wells8029 may form a frozen barrier that inhibits migration of fluid (e.g.,water) from outside the second set of freeze wells into treatment area8000. The second set of freeze wells 8029 may also form a barrier thatinhibits migration of fluid past the second set of freeze wells shouldthe frozen barrier formed by the first set of freeze wells 8028 developa breach. A frozen barrier formed by the second set of freeze wells 8029may stop migration of formation fluid and allow sufficient time for thebreach in the frozen barrier formed by the first set of freeze wells8028 to be fixed. Should a breach form in the frozen barrier formed bythe first set of freeze wells 8028, the frozen barrier formed by thesecond set of freeze wells 8029 may limit the area that formation fluidfrom the treatment area can flow into, and thus the area that needs tobe cleaned after the in situ conversion process is complete.

[1761] If the set of monitor and/or injection wells 8088 detect thepresence of formation water, a breach of the second set of freeze wells8029 may be indicated. Measures may be taken to determine the locationof the breach in the second set of freeze wells 8029. After determiningthe location of the breach, measures may be taken to stop the breach. Inan embodiment, an additional freeze well or freeze wells may be insertedinto the formation between the second set of freeze wells 8029 and theset of monitor and/or injection wells 8088 to seal the breach.

[1762] In many embodiments, monitor and/or injection wells 8088 may notdetect a breach in the frozen barrier formed by the first set of freezewells 8028 during the in situ conversion process. To clean the treatmentarea after completion of the in situ conversion processes, the first setof freeze wells 8028 may be deactivated. Fluid may be introduced throughmonitor and/or injection wells 8088 to raise the temperature of thefrozen barrier and force fluid back towards treatment area 8000. Thefluid forced into treatment area 8000 may be produced from productionwells in the treatment area. If a breach of the frozen barrier formed bythe first set of freeze wells 8028 is detected during the in situconversion process, monitor and/or injection wells 8088 may be used toremediate the area between the first set of freeze wells 8028 and thesecond set of freeze wells 8029 before, or simultaneously with,deactivating the first set of freeze wells. The ability to maintain thefrozen barrier formed by the second set of freeze wells 8029 after insitu conversion of hydrocarbons in treatment area 8000 is complete mayallow for cleansing of the treatment area with little or no possibilityof spreading contaminants beyond the second set of freeze wells 8029.

[1763] The set of monitor and/or injection wells 8088 may be positionedat a distance between the first set of freeze wells 8028 and the secondset of freeze wells 8029 to inhibit the monitor and/or injection wellsfrom becoming frozen. In some embodiments, some or all of the monitorand/or injection wells 8088 may include a heat source or heat sources(e.g., an electric heater, circulated fluid line, etc.) sufficient toinhibit the monitor and/or injection wells from freezing due to the lowtemperature zones created by freeze wells 8028 and freeze wells 8029.

[1764] In some in situ conversion process embodiments, a treatment areamay be treated sequentially. An example of sequentially treating atreatment area with different processes includes installing a pluralityof freeze wells within a formation around a treatment area. Pumpingwells are placed proximate the freeze wells within the treatment area.After a low temperature zone is formed, the pumping wells are engaged toreduce water content in the treatment area. After the pumping wells havereduced the water content, the low temperature zone expands to encompasssome of the pumping wells. Heat is applied to the treatment area usingheat sources. A mixture is produced from the formation. After a majorityof recoverable liquid hydrocarbons is recovered from the formation,synthesis gas generation is initiated. Following synthesis gasgeneration, the treatment area is used as a storage unit for fluidsdiverted from other treatment areas within the formation. The divertedfluids are produced from the treatment area. Before the low temperaturezone is allowed to thaw, the treatment area is remediated. A firstportion of a low temperature zone surrounding the pumping wells isallowed to thaw, exposing an unaltered portion of the formation. Wateris provided to a second portion of a low temperature zone to form afrozen barrier zone. A drive fluid is provided to the treatment areathrough the pumping wells. The drive fluid may move some fluidsremaining in the formation towards wells through which the fluids areproduced. This movement may be the result of steam distillation oforganic compounds, leaching of inorganic compounds into the drive fluidsolution, and/or the force of the drive fluid “pushing” fluids from thepores. Drive fluid is injected into the treatment area until the removeddrive fluid contains concentrations of the remaining fluids that fallbelow acceptable levels. After remediation of a treatment area, carbondioxide is injected into the treatment area for sequestration.

[1765] An alternate example of formation use includes a plurality offreeze wells placed within a formation surrounding a treatment area. Alow temperature zone may be formed around the treatment area. Pumpingwells, heat sources, and production wells are disposed within thetreatment area. Hot water, or water heated in situ by heat sources, maybe introduced into the treatment area to solution mine portions of theformation adjacent to selected wells. After solution mining, thetreatment area may be dewatered. The temperature of the treatment areamay be raised to pyrolysis temperatures, and pyrolysis products may beproduced from the treatment area.

[1766] After pyrolysis, the treatment area may be subjected to asynthesis gas generation process. After synthesis gas generation, thetreatment area may be cleaned. A drive fluid (e.g., water and/or steam)may be introduced into the treatment area to remove (e.g., by steamdistillation) hydrocarbons out of the treatment area. The drive fluidmay be introduced into the treatment area from an outer perimeter of thetreatment area. The drive fluid and any materials in front of, orentrained in, the drive fluid may be produced from production wells inthe interior of the treatment area. After cleaning, the treatment areamay be used as storage for selected products, as an emergency storagefacility, as a carbon dioxide sequestration bed, or for other uses.

[1767] In certain embodiments, adjacent treatment areas may beundergoing different processes concurrently within separate lowtemperature zones. These differing processes may have variedrequirements, for example, temperature and/or required constituents,which may be added to the section. In an embodiment, a low temperaturezone may be sufficient to isolate a first treatment area from a secondtreatment area. An example of differing conditions required by twoprocesses includes a first treatment area undergoing production ofhydrocarbons. In situ generation of synthesis gas may requiretemperatures greater than about 400° C. A second treatment area adjacentto the first may undergo sequestration, a process, which depending onthe component being sequestered, may be optimized at a temperature lessthan about 100° C. Alternatively, providing a barrier to both mass andheat transfer may be necessary in some embodiments. A frozen barrierzone may be utilized to isolate a treatment area from the surroundingformation both thermally and hydraulically. For example, a firsttreatment area undergoing pyrolysis should be isolated both thermallyand hydraulically from a second treatment area in which fluids are beingstored.

[1768] As depicted in FIG. 268 and FIG. 269, dewatering wells 8028 maysurround treatment area 8000. Dewatering wells 8028 that surroundtreatment area 8000 may be used to provide a barrier to fluid flow intothe treatment area or migration of fluid out of the treatment area intosurrounding formation. In an embodiment, a single ring of dewateringwells 8028 surrounds treatment area 8000. In other embodiments, two ormore rings of dewatering wells surround a treatment area. In someembodiments that use multiple rings of dewatering wells 8028, a pressuredifferential between adjacent dewatering well rings may be minimized toinhibit fluid flow between the rings of dewatering wells. Duringprocessing of treatment area 8000, formation water removed by dewateringwells 8028 in outer rings of wells may be substantially the same asformation water in areas of the formation not subjected to in situconversion. Such water may be released with no treatment or minimaltreatment. If removed water needs treatment before being released, thewater may be passed through carbon beds or otherwise treated beforebeing released. Water removed by dewatering wells 8028 in inner rings ofwells may contain some hydrocarbons. Water with significant amounts ofhydrocarbon may be used for synthesis gas generation. In someembodiments, water with significant amounts of hydrocarbons may bepassed through a portion of formation that has been subjected to in situconversion. Remaining carbon within the portion of the formation maypurify the water by adsorbing the hydrocarbons from the water.

[1769] In some embodiments, an outer ring of wells may be used toprovide a fluid to the formation. In some embodiments, the providedfluids may entrain some formation fluids (e.g., vapors). An inner ringof dewatering wells may be used to recover the provided fluids andinhibit the migration of vapors. Recovered fluids may be separated intofluids to be recycled into the formation and formation fluids. Recycledfluids may then be provided to the formation. In some embodiments, apressure gradient within a portion of the formation may increaserecovery of the provided fluids.

[1770] Alternatively, an inner ring of wells may be used for dewateringwhile an outer ring is used to reduce an inflow of groundwater. Incertain embodiments, an inner ring of wells is used to dewater theformation and fluid is pumped into the outer ring to confine vapors tothe inner area.

[1771] Water within treatment area 8000 may be pumped out of thetreatment area prior to or during heating of the formation to pyrolysistemperatures. Removing water prior to or during heating may limit thewater that needs to be vaporized by heat sources so that the heatsources are able to raise formation temperatures to pyrolysistemperatures more efficiently.

[1772] In some embodiments, well spacing between dewatering wells 8028may be arranged in convenient multiples of heater and/or production wellspacing. Some dewatering wells may be converted to heater wells and/orproduction wells during in situ processing of an oil shale formation.Spacing between dewatering wells may depend on a number of factors,including the hydrology of the formation. In some embodiments, spacingbetween dewatering wells may be 2 m, 5 m, 10 m, 20 m, or greater.

[1773] A spacing between dewatering wells and ICP wells, such as heatsources or production wells, may need to be large. The spacing may needto be large so that the dewatering wells and the in situ process wellsare not influenced by each other. In an embodiment, a spacing betweendewatering wells and in situ process wells may need to be 30 m or more.Greater or lesser spacings may be used depending on formationproperties. Also, a spacing between a property line and dewatering wellsmay need to be large so that dewatering does not influence water levelson adjacent property.

[1774] In some embodiments, a perimeter barrier or a portion of aperimeter barrier may be a grout wall, a cement barrier, and/or a sulfurbarrier. For shallow formations, a trench may be formed in the formationwhere the perimeter barrier is to be formed. The trench may be filledwith grout, cement, and/or molten sulfur. The material in the trench maybe allowed to set to form a perimeter barrier or a portion of aperimeter barrier.

[1775] Some grout, cement, or sulfur barriers may be formed in drilledcolumns along a perimeter or portion of a perimeter of a treatment area.A first opening may be formed in the formation. A second opening may beformed in the formation adjacent to the first opening. The secondopening may be formed so that the second opening intersects a portion ofthe first opening along a portion of the formation where a barrier is tobe formed. Additional intersecting openings may be formed so that aninterconnected opening is formed along a desired length of treatmentarea perimeter. After the interconnected openings are formed, a portionof the interconnected opening adjacent to where a barrier is to beformed may be filled with material such as grout, cement, and/or sulfur.The material may be allowed to set to form a barrier.

[1776] In situ treatment of formations may significantly alter formationcharacteristics such as permeability and structural strength. Productionof hydrocarbons from a formation corresponds to removal of hydrocarboncontaining material from the formation. Heat added to the formation may,in some embodiments, fracture the formation. Removal of hydrocarboncontaining material and formation of fractures may influence thestructural integrity of the formation. Selected areas of a treatmentarea may remain untreated to promote structural integrity of theformation, to inhibit subsidence, and/or to inhibit fracturepropagation.

[1777]FIG. 244 depicts a formation separated into a number of treatmentareas 8000. Freeze wells 8012 surrounding treatment areas 8000 may formlow temperature zones around the treatment areas. Formation materialwithin the low temperature zones may be untreated formation materialthat is not exposed to high temperatures during an in situ conversionprocess. Formation water may be frozen in the low temperature zone. Thefrozen water may provide additional structural strength to the formationduring the in situ conversion process. After completion of processingand use of a treatment area, maintenance of the low temperature zone maybe ended and temperature of material within the low temperature zone mayreturn to ambient conditions. The untreated formation material that wasin the low temperature zone may provide structural strength to theformation. The regions of untreated formation may inhibit subsidence ofthe formation.

[1778] In some embodiments of in situ conversion processes, portions ofa formation within a treatment area may not be subjected to temperatureshigh enough to pyrolyze or otherwise significantly change properties ofthe formation. Untreated portions of the formation may stabilize theformation and inhibit subsidence of the formation or overburden. In atreatment area, heat sources are generally placed in patterns withregular spacings between adjacent wells. The spacings may be smallenough to allow superposition of heat between adjacent heat sources. Thesuperposition of heat allows the formation to reach high temperatures. Aregular pattern of heat sources may promote relatively uniform heatingof the treatment area.

[1779] In some embodiments, a disruption of a regular heat sourcepattern may leave sections of formation within a treatment areaunprocessed. A large distance may separate heat sources from sections ofthe formation that are to remain untreated. The distance should allowthe untreated section to be minimally influenced by adjacent heatsources. The distance may be 20 m, 25 m, or greater. In an embodiment ofan in situ treatment process that uses a triangular pattern of heatsources, a well unit (e.g., three heat sources) may be periodicallyomitted from the pattern to leave an untreated portion of formation whenthe formation is subjected to in situ conversion. In other embodiments,more wells than a single unit of wells may be omitted from the pattern(e.g., 4, 5, 6, or more heat source wells may be periodically omittedfrom an equilateral triangle heat source pattern).

[1780] In some embodiments, selected wellbores of a regular heat sourcepattern may be utilized to maintain untreated sections of formationwithin the pattern. A heat transfer fluid may be placed or circulatedwithin casings placed in the selected wellbores. The heat transfer fluidmay maintain adjacent portions of the formation at low enoughtemperatures that allow the portions to be uninfluenced or minimallyinfluenced by heat provided to the formation from adjacent heat sources.The use of selected wellbores to maintain untreated portions of theformation within a treatment area may advantageously eliminate the needto make wellbore pattern alterations during well installation.

[1781] In some embodiments, water may be used as a heat transfer fluidplaced or circulated in selected casings to maintain untreated portionsof a formation. In some embodiments, the heat transfer fluid circulatedin selected casings to maintain untreated portions of formation mayinclude refrigerant utilized to form a low temperature zone around atreatment area. The refrigerant may be circulated in the selected wellsprior to initiation of formation heating so that low temperature zonesare formed around the selected freeze wells. Water in the formation mayfreeze in columns around the selected wells. Heating of the formationmay reduce the size of the columns around the freeze wells, but thefreeze wells should maintain frozen, untreated portions of the formationwithin a heated portion of the formation. The untreated portions mayprovide structural strength to the formation during an in situconversion process and after the in situ conversion process iscompleted.

[1782] Vapor processing facilities that treat production fluid from aformation may include facilities for treating generated hydrogen sulfideand other sulfur containing compounds. The sulfur treatment facilitiesmay utilize a modified Claus process or other process that produceselemental sulfur. Sulfur may be produced in large quantities at an insitu conversion process site.

[1783] Some of the sulfur produced may be liquefied and placed (e.g.,injected) in a spent formation. Stabilizers and other additives may beintroduced into the sulfur to adjust the properties of the sulfur. Forexample, aggregate such as sand, corrosion inhibitors, and/orplasticizers may be added to the molten sulfur. U.S. Pat. No. 4,518,548and U.S. Pat. No. 4,428,700, which are both incorporated by reference asif fully set forth herein, describe sulfur cements.

[1784] A spent formation may be highly porous and highly permeable.Liquefied sulfur may diffuse into pore space within the formation formedby thermally processing hydrocarbons within the formation. The sulfurmay solidify in the formation when the sulfur cools below the meltingtemperature of sulfur (approximately 115° C.). Solidified sulfur mayprovide structural strength to the formation and inhibit subsidence ofthe formation. Solidified sulfur in pore spaces within the formation mayprovide a barrier to fluid flow. If needed at a future time, sulfur maybe produced from the formation by heating the formation and removing thesulfur from the formation.

[1785] In some in situ conversion process embodiments, molten sulfur maybe placed in a formation to form a perimeter barrier around a portion ofthe formation to be subjected to pyrolysis. The perimeter barrier formedby solidified sulfur may provide structural strength to the formation.The perimeter barrier may need to be located a large distance away fromICP wells used during in situ conversion so that heat applied to thetreatment area does not affect the sulfur barrier. In some embodiments,the perimeter barrier may be 20 m, 30 m, or farther away from heatsources of an in situ conversion process system.

[1786] Sulfur barriers may be used in conjunction with a low temperaturezone formed by freeze wells. A low temperature zone, or freeze wall, maybe formed to provide a barrier to fluid flow into or out of a treatmentarea that is subjected to an in situ conversion process. The lowtemperature zone may also provide structural strength to the formationbeing treated. After the treatment area is processed, water or otherfluid may be introduced into the formation to remediate any contaminantswithin the treatment area. Heat may be recovered from the formation byremoving the water or other fluid from the formation and utilizing theheat transferred to the water or fluid for other purposes. Recoveringheat from the formation may reduce the temperature of the formation to atemperature in the vicinity of the melting temperature of sulfuradjacent to the low temperature zone.

[1787] After a temperature of the treatment area is reduced to about thetemperature of molten sulfur, molten sulfur may be introduced into theformation adjacent to the low temperature zone formed by freeze wells,and the molten sulfur may be allowed to diffuse into the formation. Inthe embodiment depicted in FIG. 247, the molten sulfur may be introducedinto the formation through dewatering well 8028. The molten sulfur maysolidify against the frozen barrier formed by freeze well 8012. Aftersolidification of the sulfur, maintenance of the low temperature zonemay be reduced or stopped.

[1788] Solid sulfur within pore spaces may inhibit fluid from migratingthrough the sulfur barrier. For example, carbon dioxide may be adsorbedonto carbon remaining in a formation that has been processed using an insitu conversion process. If water migrates into the formation, the watermay desorb the stored carbon dioxide from the formation. Sulfur injectedinto wells may solidify in pore spaces within the formation to form asulfur cement barrier. The sulfur cement barrier may inhibit watermigration into the formation. The barrier formed by the sulfur mayinhibit removal of stored carbon dioxide from the formation. In someembodiments, sulfur may be introduced throughout a formation instead ofjust as a perimeter barrier. Sulfur may be stored or used to inhibitsubsidence of the formation.

[1789] In some instances, shut-in management of the in situ treatment ofa formation may become necessary. “Shut-in” may be a reduction orcomplete termination of production from a formation undergoing in situtreatment. Adverse events of any kind and/or scheduled maintenance mayrequire shut-in of an in situ treatment process. For example, adverseevents may include malfunctioning or nonfunctioning surface facilities,lack of transport facilities to move products away from the project,breakthrough to the surface or an aquifer, and/or sociopolitical eventsnot directly related to a project.

[1790] Generally, thermal conduction and conversion of hydrocarbonsduring in situ treatment are relatively slow processes. Therefore,shut-in of production may require a relatively long period of time. Forexample, at least some hydrocarbons in the formation may continue to beconverted for months or years after heating from the heat sources isterminated. Consequently, hydrocarbons and other vapors may continue tobe generated, accompanied by a build up of fluid pressure in theformation. Fluid pressure in the formation may exceed the fracturingstrength of the formation and create fractures. As a result,hydrocarbons and other vapors, which may include hydrogen sulfide, maymigrate through the fractures to the surrounding formation, potentiallyreaching groundwater or the surface.

[1791] Shut-in management of an in situ treatment process may include avariety of steps that alleviate problems associated with shut-in of theprocess. In one embodiment, substantially all heating from heat sources,including heater wells and thermal injection, may be terminated.Termination of heating is particularly important if the adverse event orshut down may be of long duration. In addition, substantially allhydrocarbon vapors generated may be produced from the formation. Theproduced hydrocarbon vapors may be flared. “Flaring” is oxidation orburning of fluids produced from a formation. It is particularlyadvantageous for complete combustion of H₂S to take place. Furthermore,it is desirable to flare methane since methane may be a much strongergreenhouse gas than CO₂.

[1792] In certain embodiments, the fluid pressure in the formation maybe maintained below a safe level. The safe fluid pressure level may bebelow an established threshold at which fracturing and breakthroughoccur in the formation. The fluid pressure in the formation may bemonitored by several methods, for example, by passive acousticmonitoring to detect fracturing. “Passive acoustic monitoring” detectsand analyzes microseismic events to determine fracturing in a formation.In an embodiment, a short term response to excessive pressure build upmay be to release formation fluids to other storage (e.g., a spent, coolportion of the formation). Alternatively, formation fluids may beflared.

[1793] In some embodiments, produced formation fluid may be injected andstored in spent formations. A spent formation may be retainedspecifically for receiving produced fluids should a shut-in situationarise. Fluid communication between the spent formation and thesurrounding formation may be limited by a barrier (e.g., a frozenbarrier, a sulfur barrier, etc.). The barrier may inhibit flow of theproduced formation fluid from the spent formation. In an embodiment, thetemperature of the spent formation may be low enough to condense asubstantial portion of condensable fluids. There may be a correspondingdecrease in fluid pressure as formation fluid condenses in the spentformation. The decrease in fluid pressure and volume reduction mayincrease storage capacity of the spent formation. In an embodiment,subsequent heating of the spent formation may allow substantiallycomplete recovery of stored hydrocarbons.

[1794] In certain embodiments, produced formation fluid may be injectedinto relatively high temperature formations. The formation may haveportions with an average temperature high enough to convert asubstantial portion of the injected formation fluid to coke and H₂. H₂may be flared to produce water vapor in some embodiments.

[1795] In an embodiment, produced formation fluid may be injected intopartially produced or depleted formations. The depleted formations mayinclude oil fields, gas fields, or water zones with established seal andtrap integrity. The trapped formation fluid may be recovered at a latertime. In other embodiments, formation fluid may be stored in surfacestorage units.

[1796]FIG. 284 is a flow chart illustrating options for produced fluidsfrom a shut-in formation. Stream 8252 may be produced from shut-information 8250. Stream 8252 may be injected into cooled spent formation8254. Formation 8254 may be reheated at a later time to produce thestored formation fluid, as shown by stream 8255. In addition, stream8252 may be injected into hot formation 8256. A substantial portion ofthe fluids injected into formation 8256 may be converted to coke and H₂.The H₂ may be produced from formation 8256 as stream 8257 and flared.Alternatively, stream 8252 may be injected into depleted oil or gasfield or water zone 8258. Injected formation fluid may be produced at alater time, as stream 8259 illustrates. Furthermore, stream 8252 may bestored in surface storage facilities 8260.

[1797] After completion of an in situ conversion process, formations maybe subjected to additional treatment processes in preparation forabandonment. Processes which may be performed in a formation mayinclude, but are not limited to, recovery of thermal energy from theformation, removal of fluids generated during the in situ conversionprocess through injection of a fluid (water, carbon dioxide, drivefluid), and/or recovery of thermal energy from a frozen barrier orfreeze well.

[1798] Thermal energy may be recovered from formations through theinjection of fluids into the formation. Fluids may be injected and/orremoved through existing heater wells, dewatering wells, and/orproduction wells. In some embodiments, a portion of a formationsubjected to an in situ conversion process may be at an averagetemperature greater than about 300° C. The portion of the formation mayhave a relatively high porosity (e.g., greater than about 20%) and apermeability greater than about 0.3 darcy (e.g., 0.4 darcy, 0.6 darcy,0.9 darcy, 1 darcy, or greater) due to the removal of hydrocarbons fromthe formation and thermal fracturing of the formation. The increasedporosity and permeability of the section may reduce the number of wellsneeded to inject and recover fluid. For example, water may be providedto or be removed from the formation using heater wells that allow, orhave been reworked to allow, fluid communication between the well andthe surrounding formation.

[1799] In some embodiments, fresh water may be injected into theformation. Alternatively, non-potable water, hydrocarbon containingwater, brine, acidic water, alkaline water, or combinations thereof maybe injected into the formation. Compounds in the water may be leftwithin the formation after the water is vaporized by heat within theformation. Some compounds within the water may be absorbed and/oradsorbed onto remaining material within the formation. Introduction ofseveral pore volumes of water may be needed to lower the averagetemperature in the formation below the boiling point of water. In anembodiment, water injection may include geothermal well and othertechnologies developed for utilizing the steam production from hightemperature subterranean formations.

[1800] In certain embodiments, applications of steam recovered from theformation may include direct use for power generation and/or use assensible energy in heat exchange mechanisms. In particular, thermalenergy from recovered steam may be used in project surface facilities(e.g., in heat exchange units, in the desalinization process, or in thedistillation of produced water). The thermal energy from recovered steammay be used for solution mining of nearby mineral resources (e.g.,nahcolite, sulfur, phosphates, etc). Thermal energy from recovered steammay also be used in external industrial applications, such asapplications that require the use of large volumes of steam. Inaddition, thermal energy from recovered steam may be used for municipalpurposes (e.g., heating buildings) and for agricultural purposes (e.g.,heating hothouses or processing products).

[1801] In an in situ conversion process embodiment during a time priorto abandonment, substantially non-reactive gas (e.g., carbon dioxide)may be used as a heat recovery fluid. The substantially non-reactive gasmay be injected into the formation and heat within the formation may betransferred to the substantially non-reactive gas. In some embodiments,the substantially non-reactive gas may recover a substantial portion ofresidual treatment fluids (e.g., low molecular weight hydrocarbons). Thetreatment fluids may be separated from the substantially non-reactivegas at the surface of the formation. For example, some carbon dioxidemay be adsorbed onto the surface of the formation, displacing lowmolecular weight hydrocarbons. In an embodiment, carbon dioxide adsorbedonto formation surfaces during use as a heat recovery fluid may besequestered within the formation. After completion of heat recovery,additional carbon dioxide may be provided to the formation and adsorbedin formation pore spaces for sequestration.

[1802] In an in situ conversion process embodiment, recovery of storedheat in a formation with injected substantially non-reactive gas mayrequire more pore volumes of gas than would have been required had waterbeen used as the heat recovery fluid. This may be due to gases generallyhaving lower sensible heats than liquids. In addition, substantiallynon-reactive gas injection may require initial compression of theinjected gas stream. However, injection and recovery in the gas phasemay be easier than in the liquid phase. In certain embodiments, recoveryof heat from the formation may combine injection of water andsubstantially non-reactive gas. For example, substantially non-reactivegas injection may be performed first, followed by water injection.

[1803] In some embodiments, the formation may be cooled such that anaverage temperature of the formation is at least below the ambientboiling temperature of water. Injection and recovery of fluid may berepeated until the average temperature of the formation is below theambient boiling point at the fluid pressure in the formation.

[1804]FIG. 271 illustrates a schematic of an embodiment of heat recoveryfrom a formation previously subjected to an in situ conversion process.FIG. 271 includes formation 8278 with heat recovery fluid injectionwellbore 8280 and production wellbore 8282. The wellbores may be membersof a larger pattern of wellbores placed throughout a portion of theformation. The temperature in heated portions of the formation that areto be cooled may be between about 300° C. and about 1000° C. Thermalenergy may be recovered from the heated portions of the formation byinjecting a heat recovery fluid. Heat recovery fluid 8284, such as waterand/or carbon dioxide, may be injected into wellbore 8280. A portion ofinjected water may be vaporized to form steam. A portion of injectedcarbon dioxide may adsorb on the surface of the carbon in the formation.Gas mixture 8286 may exit continuously from wellbore 8282. Gas mixture8286 may include the heat recovery fluid (e.g., steam or carbondioxide), hydrocarbons, and/or contaminants. Contaminants andhydrocarbons may be separated from the gas mixture in a surfacefacility. The heat recovery fluid may be recycled back into theformation.

[1805] In an in situ conversion process embodiment, heat recovery fromthe formation may be performed in a batch mode. Injection of the heatrecovery fluid may continue for a period of time (e.g., until the porevolume of the portion of the formation is substantially filled). After aselected period of time subsequent to ceasing injection of heat recoveryfluid, gas mixture 8286 may be produced from the formation throughwellbore 8282. In an embodiment, the gas mixture may also exit throughwellbore 8280. The selected period of time may be, in some embodiments,about one month.

[1806] In one embodiment, gas mixture 8286 may be fed to surfaceseparation unit 8288. Separation unit 8288 may separate gas mixture 8286into heat recovery fluid 8290 and hydrocarbons and components 8296. Theheat recovery fluid may be used in power generation units 8292 or heatexchange mechanisms 8294. In another embodiment, gas mixture 8286 may befed directly from the formation to power generation units or heatexchange mechanisms. Injection of the heat recovery fluid may becontinued until a portion of the formation reaches a desiredtemperature. For example, if water is used as the heat recovery fluid,water injection may continue until the formation cools to, or is at atemperature below, the boiling point of water at formation pressure.

[1807] Thermal processing and increasing the permeability of a formationmay allow some components (e.g., hydrocarbons, metals and/or residualformation fluids) in the formation to migrate from a treatment area toareas adjacent to the formation. Such components may be created duringthermal processing of the formation. Such components may be present inhigher quantities if the formation is not subjected to a synthesis gasgeneration cycle after pyrolysis. In one embodiment, a recovery fluidmay be introduced into the formation to remove some of the components.The recovery fluid may be provided to the formation prior to and/orafter cooling of the formation has begun. The recovery fluid mayinclude, but is not limited to, water, steam, hydrogen, carbon dioxide,air, hydrocarbons (e.g., methane, ethane, and/or propane), and/or acombustible gas. The provided recovery fluid may be recycled fromanother portion of the formation, another formation, and/or the portionof the formation being treated. In some embodiments, a portion of therecovery fluid may react with one or more materials in the formation tovolatize and/or neutralize at least some of the material. In alternateembodiments, the recovery fluid may force components in the formation tobe produced. After production the recovery fluid may be provided to anenergy producing unit (e.g. turbine or combustor). For example, methanemay be provided to a portion of the formation. Heat within the formationmay transfer to the methane. The methane may cause production of amixture including heavier hydrocarbons (e.g., BTEX compounds). Themixture may be provided to a turbine, where some of the mixture iscombusted to produce electricity. In alternate embodiments, water may beprovided to the formation as a recovery fluid. Steam produced from thewater may entrain, distill, and/or drive components within the formationto production wells. In an embodiment, organic components may beproduced from the formation either by steam distillation and/orentrainment in steam. In some embodiments, inorganic components may beentrained and produced in condensed water in the formation. Waterinjection and steam recovery may be continued until safe and permissiblelevels of components are achieved. Removal of these components may occurafter an in situ conversion process is complete.

[1808] Remediation within a treatment area surrounded by a barrier(e.g., a frozen barrier) may inhibit the migration of components fromthe treatment area to the surrounding formation. A plurality of freezewells 8012 may be used to form frozen barrier zone 8002 and define avolume to be treated within hydrocarbon containing material 8006, asillustrated in FIG. 406. Frozen barrier 8002 may inhibit fluid flow intoor out of treatment area 6510. In an in situ conversion processembodiment, a recovery fluid may be introduced into the formation nearfreeze wells 8012 after treatment is complete. Injection wells 6902 usedfor injection of the recovery fluid may include, but are not limited to,pumping wells, heat sources, freeze wells, dewatering wells, and/orproduction wells that have been converted into injection wells. Incertain embodiments, wells used previously may have a sealed casing. Thesealed casing may be perforated to permit fluid communication betweenthe well and the surrounding formation. Recovery fluid may move some ofthe components in the formation towards one or more removal wells 6904.Removal wells 6904 may include wells that were converted from heatsources and/or production wells. In an alternate embodiment, a recoveryfluid may be introduced into a treatment area through an innermostproduction well, or a production well ring, that is converted into aninjection well.

[1809] In some embodiments, the recovery fluid may be introduced intothe formation after the frozen barrier zone has been partially thawed.When thawing the frozen barrier, thermal energy may be removed from thefrozen barrier by circulating various fluids through the freeze well.For example, a warm refrigerant may be injected into the freeze wellsystem to be cooled and used in a surface treatment unit, a freeze wellsystem, and/or other treatment area. As the temperature within thefreeze well increases, various other fluids (e.g., water, substantiallynon-reactive gas, etc.) may be utilized to raise the temperature of thefreeze well. Thawed freeze wells that are exposed may be converted foruse as injection wells 6902 to introduce recovery fluid into theformation. Introduction of the recovery fluid may heat the regionadjacent to the inner row of freeze wells to an average temperature ofless than a pyrolysis temperature of hydrocarbon material in theformation. The heat from the recovery fluid may move mobilizedhydrocarbon and inorganic components. Movement of the hydrocarbon andinorganic components may be due in part to steam distillation of thefluids and/or entrainment. Introducing the recovery fluid at a pointwhere the formation was previously frozen ensures that the hydrocarbonmaterial at the injection well is unaltered. The unaltered hydrocarbonmaterial may be essentially in its original natural state. As such, theinjected fluid may move from a natural zone to the previously treatedarea and be produced. Thus, fluids formed during the treatment areremoved without spreading such fluids to other areas outside of thetreatment area. Alternatively, any well previously frozen in a frozenbarrier zone, such as a pumping well, may be thawed and used as aninjection well.

[1810] A volume of recovery fluid required to remediate a treatment areamay be greater than about one pore volume of the treatment area. Twopore volumes or more of recovery fluid may be introduced to remediatethe treatment area. In certain embodiments, injection of a recoveryfluid to remediate a treatment area may continue until concentrations ofcomponents in the removed recovery fluid are at acceptable levels deemedappropriate for a site. These acceptable levels may be based on baseline surveys, regulatory requirements, future potential uses of thesite, geology of the site, and accessibility. After one or morecomponents within a treatment area are removed or reduced to acceptablelevels, the treatment system for the formation, including the freezewells, may be deactivated. If a new barrier zone around a new treatmentarea is to be formed, heat may be transferred between hydrocarboncontaining material, in which a new barrier zone is to be formed, andthe initial freeze wells using a circulated heat transfer fluid. Usingdeactivated freeze wells to cool hydrocarbon containing material inwhich a low temperature zone is to be formed may allow for recovery ofsome of the energy expended to form and maintain the initial barrier. Inaddition, using thermal energy extracted from the initial barrier tocool hydrocarbon material in which a new barrier zone is to be formedmay significantly decrease a cost of forming the new barrier. In sometreatment system embodiments, a low temperature zone may be allowed toreach thermal equilibrium with a surrounding formation naturally.

[1811] In some in situ conversion process embodiments, the frozenbarrier may include an inner ring of freeze wells directly adjacent tothe treatment area and an outer ring of freeze wells directly adjacentto the untreated area. A region of the formation near the freeze wellsmay remain at a temperature below the freezing point of water duringpyrolysis and synthesis gas generation. In an embodiment, organiccontaminants from pyrolysis may migrate through thermal fractures to aregion adjacent to the inner row of freeze wells. The contaminants maybecome immobilized in fractures and pores in the region due to therelatively low temperatures of the region.

[1812] Migration of contaminants from the treatment area may be reducedor prevented by inhibiting groundwater flow through the treatment area.For example, groundwater flow may be inhibited using a barrier such as afreeze wall and/or sulfur barriers. As a result, migration ofcontaminants may be reduced or eliminated even if contaminants weredissolved in formation pore water. In addition, it may be advantageousto inhibit groundwater flow to maintain a reduced state within theformation. Oxidized metals introduced into the formation fromgroundwater flow tend to have greater mobility and may be more likely tobe released.

[1813] An embodiment for inhibiting migration of contaminants may alsoinclude sealing off the mineral matrix and residual carbon byprecipitation or evaporation of a sealing mineral phase. The sealingmineral phase may inhibit dissolution of contaminants of fluids in theformation into groundwater.

[1814] Carbon dioxide may be produced during an in situ conversionprocess or during processing of the products produced by the in situconversion process (e.g., combustion). Control and/or reduction ofcarbon dioxide production from an in situ conversion process may bedesirable. “Carbon dioxide life cycle emissions,” as used herein, isdefined as the amount of CO₂ emissions from a product as it is produced,transported, and used.

[1815] A base line CO₂ life cycle emission level may be selected forproducts produced from an in situ conversion process. The formationconditions and/or process conditions may be altered to produce productsto meet the selected CO₂ base line life cycle emission level. In someembodiments, in situ conversion products may be blended to meet aselected CO₂ base line life cycle emission level. The CO₂ life cycleemission level of a selected product is defined as a number of kilogramsof CO₂ per joule of energy (kg CO₂/J).

[1816] A hydrogen cycle, a half-way cycle, and a methane cycle areexamples of processes that may be used to produce products with selectedCO₂ emission levels less than the total CO₂ emission level that would beproduced by direct production of natural gas from a gas reservoir. Incertain embodiments, products may be combined to produce a product witha selected CO₂ emission level less than the total CO₂ emission fromdirect production of natural gas. In other embodiments, cycles may beblended to produce products with a CO₂ emission level less than thetotal CO₂ emission from direct production of natural gas. For example,in an embodiment, a methane cycle may be used in one part of aproduction field and a half-way cycle may be used in another part of theproduction field. The products produced from these two processes may beblended to produce a product with a selected CO₂ emission level. Inother embodiments, other combinations of products from the hydrogencycle, the half-way cycle, and the methane cycle may be used to producea product with a selected CO₂ emission level.

[1817] In an in situ conversion process embodiment, a formation may betreated such that hydrocarbons in the formation are converted to adesired product. The product may be produced from the formation. In somein situ conversion process embodiments, the in situ conversion processmay be operated to produce a limited amount of carbon dioxide.

[1818] In an in situ conversion process embodiment, the in situconversion process may be operated so that a substantial portion of theproduct is molecular hydrogen. There may be little or no hydrocarbonfluid recovery. An in situ conversion process that operates at a hightemperature to produce a substantial portion of hydrogen may be a“hydrogen cycle process.” A portion of the hydrogen produced during thehydrogen cycle process may be used to fuel heat sources that raiseand/or maintain a temperature within the formation to a hightemperature.

[1819] During a hydrogen cycle process, a production well and formationadjacent to the production well may be heated to temperatures greaterthan about 525° C. At such temperatures, a substantial portion ofhydrocarbons present or that flow into the production well and formationadjacent to the production well may be reduced to hydrogen and coke.There may be minimal or no production of carbon dioxide or hydrocarbons.Hydrocarbons in formation fluid produced from the formation may berecycled back into the formation through injection wells to producehydrogen and coke. Hydrogen produced from a hydrogen cycle process maybe produced through heated production wells in the formation. A portionof the produced hydrogen may be used as a fuel for heat sources in theformation. A portion of the hydrogen may be sold or used in fuel cells.In some embodiments, coke produced during a hydrogen cycle process mayslowly fill pore space within the formation adjacent to the productionwell. The coke may provide structural strength to the formation. In someembodiments, the production wells may be treated (e.g., by introducingsteam to generate synthesis gas) to remove a portion of formed coke andallow for production of formation fluid. In some embodiments, a cokedproduction well may be blocked, and formation fluid may be produced fromother production wells.

[1820] A hydrogen cycle may allow for very low CO₂ life cycle emissionlevels. In some embodiments, a hydrogen cycle process may have a CO₂life cycle emission level of about 3.3×10⁻⁹ kg CO₂/J. In otherembodiments, a CO₂ life cycle emission level of the hydrogen cycleprocess may be less than about 1.6×10⁻¹⁰ kg CO₂/J.

[1821] In an in situ conversion process embodiment, a portion offormation may be treated to produce a product that is substantially amixture of molecular hydrogen and methane. There may be little or noother hydrocarbons (i.e., ethane, propane, etc.). A process ofconverting hydrocarbons in a formation to a product that issubstantially molecular hydrogen and methane may be referred to as a“half-way cycle process.” A portion of the product may be used as a fuelfor heat sources that heat the formation to maintain and/or increase theformation temperature.

[1822] During a half-way cycle, production wells and formation adjacentto the production wells may be heated to temperatures from about 400° C.to about 525° C. A substantial portion of hydrocarbons present or thatflow into the production wells or formation adjacent to the productionwells may be reduced to molecular hydrogen and methane. The hydrogen andmethane may be produced as a mixture from the production wells. Producedhydrocarbons having carbon numbers greater than one may be recycled backinto the formation through injection wells to generate hydrogen andmethane. Formation adjacent to the production wells may slowly coke upduring a half-way cycle. When production through a production well fallsbelow a certain level, the production well may blocked in. In someembodiments, the production well may be treated (e.g., by introducingsteam to generate synthesis gas) to remove a portion of the coke andallow for increased production through the well.

[1823] In an embodiment of a half-way cycle process, produced hydrogenand methane may be separated from other produced fluid. A portion of thehydrogen and methane may be used as a fuel for heat sources. Further,hydrogen may be separated from the methane of a portion not used asfuel. In some embodiments, a portion of the hydrogen may be used forhydrogenation in another portion of the formation and/or in surfacefacilities. In some embodiments, hydrogen may be sold. In someembodiments, some or all produced methane may be used to fuel heatsources.

[1824] A mixture produced using a half-way cycle may have a CO₂ lifecycle emission level that is greater than a CO₂ life cycle emissionlevel of a hydrogen cycle. A mixture produced using a half-way cycle mayhave a CO₂ life cycle emission level of less than about 3.3×10⁻⁸ kgCO₂/J.

[1825] In an in situ conversion process embodiment, a portion offormation may be treated to produce a product that is substantiallymethane. A process of converting a substantial portion of hydrocarbonswithin a portion of formation to methane may be referred to as a“methane cycle.”

[1826] The producing wellbore and the formation proximate the producingwellbore may, in some embodiments, be heated to temperatures from about300° C. to about 500° C. For example, the producing wellbore may beheated to about 400° C. Pyrolysis in this temperature range may allow asubstantial portion of hydrocarbons in the formation to be converted tomethane. Hydrocarbons with carbon numbers greater than one produced fromthe formation may be recycled back into the formation through injectionwells to generate methane. The methane may be produced in a mixture fromthe heated wellbores. In an embodiment, the methane content may begreater than about 80 volume % of the produced fluids.

[1827] A mixture produced from a methane cycle may have a CO₂ life cycleemission level that is larger than the CO₂ life cycle emission level fora half-way cycle. In some embodiments of methane cycles, the CO₂ lifecycle emission levels are less than about 7.4×10⁻⁸ kg CO₂/J.

[1828] In an in situ conversion process embodiment, molecular hydrogenmay be produced on site using processes such as, but not limited to,Modular and Intensified Steam Reforming (MISR) and/or Steam MethaneReforming (SMR). The produced molecular hydrogen may be blended withother products to produce a product below a selected CO₂ emission level.The CO₂ produced using MISR or other processes may be sequestered in aformation.

[1829] After completion of pyrolysis and/or synthesis gas generationduring an in situ conversion process, at least a portion of theformation may be converted into a hot spent reservoir. The hot spentreservoir may have a temperature of greater than about 350° C. Theporosity may have increased by 20 volume % or more. In addition, apermeability in a hot spent reservoir may be greater than about 1 darcy,or in certain embodiments, greater than about 20 darcy. A hot spentreservoir may have a large open volume. The surface area within thevolume may have increased significantly due to the in situ conversionprocess. Utilization of the in situ conversion process may have requiredthe installation and use of production wells and heat sources spaced ata range between about 10 m and about 30 m. A barrier (e.g., freezewells) may also be present to inhibit migration of fluids to or from atreatment area in the formation.

[1830] In an in situ conversion process embodiment, a heated formation(e.g., a formation that has undergone substantial pyrolysis and/orsynthesis gas generation) may be used to produce olefins and/or otherdesired products. Hydrocarbons may be provided to (e.g., injected into)a heated portion of a formation. An in situ conversion process in aseparate portion of the formation may provide the source of thehydrocarbons. The formation temperature and/or pressure may becontrolled to produce hydrocarbons of a desired composition (e.g.,hydrocarbons with a C₂-C₇ carbon chain length). Temperature may becontrolled by controlling energy input into heat sources. Pressure maybe controlled by controlling the temperature in the formation and/or bycontrolling a rate of production of formation fluid from the formation.Pressure within a portion of a formation enclosed by a perimeter barrier(e.g., a frozen barrier and an impermeable overburden and underburden)may be controlled so that the pressure is substantially uniformthroughout the enclosed portion of formation.

[1831] Many different types of hydrocarbons may be provided to theheated formation as a feed stream. Examples of hydrocarbons include, butare not limited to, pitch, heavy hydrocarbons, asphaltenes, crude oil,naphtha, and/or condensable hydrocarbons (e.g., methane, ethane,propane, and butane). A portion of heavy and/or condensable hydrocarbonsintroduced into a heated portion of the formation may pyrolyze to formshorter chain compounds. The shorter chain compounds may have greatervalue than the longer chain compounds introduced into the portion offormation.

[1832] A portion of the hydrocarbons introduced into the formation mayreact to form olefins. An overall efficiency for producing olefins maybe relatively low (as compared to reactors designed to produce olefins),but the volume of heated formation and/or the availability of feed fromportions of the formation undergoing an in situ conversion process maymake production of olefins from a heated formation economically viable.

[1833] In certain embodiments, the temperature of a selected portion ofthe formation (e.g., near production wells) may be controlled so thathydrocarbon fluid flowing into the selected portion has an increasedchance of forming olefins. In certain embodiments, process conditionsmay be controlled such that the time period in which the compounds aresubjected to relatively higher temperatures is controlled. In certainembodiments, only a small portion of the formation (e.g., near theproduction wells) is at a high enough temperature to promote olefinformation. Olefins may be formed subsurface in the small portion, butthe olefins are produced quickly (e.g., before the olefins cancross-link in the formation and/or further react to form coke).

[1834] In an embodiment, olefins are produced from saturatedhydrocarbons. Formation of the olefins from saturated hydrocarbons alsoresults in the production of molecular hydrogen. In an embodiment,olefin production may include cracking saturated hydrocarbons in theformation and allowing the cracked hydrocarbons to further react in theformation (e.g., via alkylation or dimerization). The formation ofolefins may involve different reaction mechanisms. Any number of theolefin formation mechanisms may be present in the in situ conversionprocess. Water may be added to the formation for steam generation and/ortemperature control.

[1835] Examples of olefins produced by providing hydrocarbons to aheated formation may include, but are not limited to, ethene, propene,1-butene, 2-butene, higher molecular weight olefins, and/or mixturesthereof. The produced mixture may include from slightly over about 0weight % to about 80 weight % (e.g., from about 10-50 weight %) olefinsin a hydrocarbon portion of a produced mixture.

[1836] In an in situ conversion process embodiment, crude oil may beprovided to a heated portion of a formation. The crude oil may crack inthe heated portion to form a lighter, higher quality oil and an olefinportion. In an in situ conversion process embodiment, pitch and/orasphaltenes may be provided to a heated portion of a formation. Thepitch and/or asphaltenes may be in solution and/or entrained in asolvent. The solvent may be a hydrocarbon portion of a fluid producedfrom a portion of a formation subjected to an in situ conversionprocess. A portion of the pitch and/or asphaltenes and the solvent maybe converted in the formation to high quality hydrocarbons and/orolefins. Similarly, emulsions, bottoms, and/or undesired hydrocarboncompounds that are flowable, entrained in a flowable solution, ordissolved in a solvent may be introduced into a heated portion of aformation to upgrade the introduced fluids and/or produce olefins.

[1837] In some embodiments, a temperature in selected portions of aproduction well wellbore may be controlled to promote production ofolefins. A portion of the wellbore adjacent to a heated portion of theformation may include a heater that maintains the temperature at anelevated temperature. A portion of the wellbore above the heated portionof the wellbore may include a heat transfer line that reduces thetemperature of fluid being removed through the wellbore to a temperaturebelow reaction temperatures of desired components within the wellbore(e.g., olefins). In some embodiments, transfer of heat from the fluidsin the wellbore to the overburden may reduce the temperature of fluidsin the wellbore quickly enough to obviate the need for a heat transferline in the wellbore.

[1838] In some in situ conversion process embodiments, hydrocarbonfeedstock introduced into a hot portion of a portion may have an APIgravity of less than about 20°. The hydrocarbon feedstock may be crackedin the heated portion to produce a plurality of products. The productsmay include olefins. Molecular hydrogen may also be produced along witha mixture of products. A temperature and/or a pressure of the heatedportion of the formation may be controlled such that a substantialportion of the produced product includes olefins. A hydrocarbon portionof the produced mixture may include from about 1 weight % to about 80weight % (e.g., from about 10-50 weight %) olefins.

[1839] In some in situ conversion process embodiments, a hydrocarbonmixture produced from a formation may be suitable for use as an olefinplant feedstock. Process conditions in a portion of a formation may beadjusted to produce a hydrocarbon mixture that is suitable for use as anolefin plant feedstock. The mixture should contain relatively shortchain saturated hydrocarbons (e.g., methane, ethane, propane, and/orbutane). To change formation conditions to produce a hydrocarbon mixturesuitable for use as an olefin plant feedstock, backpressure within theformation may be maintained at an increased level (i.e., production fromproduction wells may be low enough to result in an increase in pressurein the formation).

[1840] In some in situ conversion process embodiments, low molecularweight olefins (e.g., ethene and propene) may be produced during the insitu conversion process. Fluid produced may be routed through arelatively hot (e.g., greater than about 500° C.) subsurface zone beforethe fluid is allowed to cool. The fluid may crack at a high temperatureto produce low molecular weight olefins. Temperature of the fluid shouldbe subjected to high temperature for only a short period of time toinhibit formation of methane, hydrogen, and/or coke from the lowmolecular weight olefins.

[1841] In some in situ conversion process embodiments, olefin productionyield may be facilitated from a formation. Continued processing orrecycling of the non-olefinic C₂+ products in the in situ conversionprocess may maximize ethene and/or propene yield. Control of thetemperature and residence time within a portion of the formation may beused to maximize non-olefinic C₂+ hydrocarbons and hydrogen content.Some olefins may be produced in this cycle and separated from theproduced fluid. The non-olefinic portion may be recycled to a secondsection of the formation that includes production wells that are heated.A portion of the introduced hydrocarbons may be converted into olefinsby the heated production wells to increase the yield of olefins obtainedfrom the formation.

[1842] In some in situ conversion process embodiments, linear alphaolefins in the C₄-C₃₀ range may be produced from shale oil. Formationconditions may be controlled to facilitate formation and production ofolefins in a desired range (e.g., C₆-C₁₆ alpha olefins). Shale oil mayproduce paraffinic (i.e., waxy) and linear compounds during the in situconversion process. Linear alpha olefins may be produced from the insitu conversion process by varying the temperature, residence time,and/or pressure in the formation being treated. Some other types of oilshale formations may promote the production of shorter chain olefins.For example, kerogen containing formations may produce lower molecularweight olefins (e.g., ethene, propene, butene, and/or isomers thereof)instead of longer chain olefins (e.g., chains having greater than 5carbon atoms).

[1843] Some in situ conversion processes may be run at sufficientpressure to generate a desirable steam cracker feed. A desirable steamcracker feed may be a feed with relatively high hydrocarbon content(e.g., a relatively high alkane content) and relatively low oxygen,sulfur, and/or nitrogen content. A desirable steam cracker feed mayreduce the need to treat the stream before processing in a steam crackerunit. Therefore, the desirable feed may be run directly from the in situconversion process to a steam cracker unit. The steam cracker unit mayproduce olefins from the feed stream.

[1844] In an in situ conversion process embodiment, a heated formationmay be used to upgrade materials. Materials to be upgraded may beproduced from the same portion of the formation and recycled, producedfrom other formations, or produced from other portions of the sameformation.

[1845] During some in situ conversion process embodiments in selectedformations only a selected portion of a formation may be heated torelatively high temperatures (e.g., a temperature sufficient to causepyrolysis). Other portions of the formation may still produce heavyhydrocarbons but may not be heated, or may only be partially heated(e.g., by steam, heat sources, or other mechanisms). The heavyhydrocarbons produced from the other less heated or unheated portions ofthe formation may be introduced into the portion of the formation thatis heated to a relatively high temperature. The high temperature portionof the formation may upgrade the introduced heavy hydrocarbons. Energysavings may be achieved since only a portion of the formation is heatedto a relatively high temperature.

[1846] In an embodiment, surface mined tar may be upgraded in a heatedformation. The tar may be processed to produce separated hydrocarbons(e.g., tar). A portion of the tar may be heated, entrained, and/ordissolved in a solvent to produce a flowable fluid. The solvent may be aportion of hydrocarbon fluid produced from the formation. The flowablefluid may be introduced into the heated portion of the formation.

[1847] Emulsions may be produced during some metal processing and/orhydrocarbon processing procedures. Some emulsions may be flowable. Otheremulsions may be made flowable by the introduction of heat and/or acarrier fluid. The carrier fluid may be water and/or hydrocarbon fluid.The hydrocarbon fluid may be a fluid produced during an in situ process.A flowable emulsion may be introduced into a heated portion of aformation being subjected to in situ processing. In some embodiments,the heated portion may break the emulsion. The components of theemulsion may pyrolyze or react (e.g., undergo synthesis gas reactions)in the heated formation to produce desired products from productionwells. In some embodiments, the emulsion or components of the emulsionmay remain in the formation.

[1848] Upgrading may include, but is not limited to, changing a productcomposition, a boiling point, or a freezing point. Examples of materialsthat may be upgraded include, but are not limited to, heavyhydrocarbons, tar, emulsions (e.g., emulsions from surface separation oftar from sand), naphtha, asphaltenes, and/or crude oil. In certainembodiments, surface mined tar may be injected into a formation forupgrading. Such surface mined tar may be partially treated, heated, oremulsified before being provided to a formation for upgrading. Thematerial to be upgraded may be provided to the heated portion of theformation. The material may be upgraded in the formation. For example,upgrading may include providing heavy hydrocarbons having an API gravityof less than about 20°, 15°, 10°, or 5° into a heated portion of theformation. The heavy hydrocarbons may be cracked or distilled in theheated portion. The upgraded heavy hydrocarbons may have an API gravityof greater than about 20° (or above about 25° or above 30°). Theupgraded heavy hydrocarbons may also have a reduced amount of sulfurand/or nitrogen. A property of the upgraded hydrocarbons (e.g., APIgravity or sulfur content) may be measured to determine the relativeupgrading of the hydrocarbons.

[1849] In some in situ conversion process embodiments, fluid producedfrom a formation may be fractionated in an above ground facility toproduce selected components. The relatively heavier molecular weightcomponents (e.g., bottom fractions from distillation columns) may berecycled into a formation. The heated formation may upgrade therelatively heavier molecular weight components.

[1850] In some in situ conversion process embodiments, heavyhydrocarbons may be produced at a first location. The heavy hydrocarbonsmay be diluted with a diluent to enable the heavy hydrocarbons to bepumped or otherwise transported to a different location. The mixture ofheavy hydrocarbons and diluent may be separated at the heated formationprior to providing the heavy hydrocarbons mixture to the heatedformation for upgrading. Alternately, the mixture of heavy hydrocarbonsand diluent may be directly injected into a heated formation forupgrading and separation in the heated formation. In certainembodiments, a hot fluid (e.g., steam) may be added to the heavyhydrocarbons mixture to allow fluid cracking in the heated formation.Steam may inhibit coking in the formation, lessen the partial pressureof hydrocarbons in the formation, and/or provide a mechanism to sweepthe formation. Controlling the flow of steam may provide a mechanism tocontrol the residence time of the hydrocarbons in the heated formation.The residence time of the hydrocarbons in the heated formation may beused to control or adjust the molecular weight and/or API gravity of aproduct produced from the heated formation.

[1851] In an in situ conversion process embodiment, crude oil producedfrom a formation by conventional methods may be upgraded in a heatedformation of the in situ conversion process system. The crude oil may beprovided to a heated portion of the formation to upgrade the oil. Insome embodiments, only a heavy fraction of the crude oil may beintroduced into the heated formation. The heated portion of theformation may upgrade the quality of the introduced portion of the oiland/or remove some of the undesired components within the introducedportion of the crude oil (e.g., sulfur and/or nitrogen).

[1852] In some embodiments, hydrogen or any other hydrogen donor fluidmay be added to heavy hydrocarbons injected into a heated formation. Thehydrogen or hydrogen donor may increase cracking and upgrading of theheavy hydrocarbons in the heated formation. In certain embodiments,heavy hydrocarbons may be injected with a gas (e.g., hydrogen or carbondioxide) to increase and/or control the pressure within the heatedformation.

[1853] In an in situ conversion process embodiment, a heated portion ofa formation may be used as a hydrotreating zone. A temperature andpressure of a portion of the formation may be controlled so thatmolecular hydrogen is present in the hydrotreating zone. For example, aheat source or selected heat sources may be operated at hightemperatures to produce hydrogen and coke. The hydrogen produced by theheat source or selected heat sources may diffuse or be drawn by apressure gradient created by production wells towards the hydrotreatingzone. The amount of molecular hydrogen may be controlled by controllingthe temperature of the heat source or selected heat sources. In someembodiments, hydrogen or hydrogen generating fluid (e.g., hydrocarbonsintroduced through or adjacent to a hot zone) may be introduced into theformation to provide hydrogen for the hydrotreating zone.

[1854] In an in situ conversion process embodiment, a compound orcompounds may be provided to a hydrotreating zone to hydrotreat thecompound or compounds. In some embodiments, the compound or compoundsmay be generated in the formation by pyrolysis reactions of nativehydrocarbons. In other embodiments, the compound or compounds may beintroduced into the hydrotreating zone. Examples of compounds that maybe hydrotreated include, but are not limited to, oxygenates, olefins,nitrogen containing carbon compounds, sulfur containing carboncompounds, crude oil, synthetic crude oil, pitch, hydrocarbon mixtures,and/or combinations thereof.

[1855] Hydrotreating in a heated formation may provide advantages overconventional hydrotreating. The heated reservoir may function as a largehydrotreating unit, thereby providing a large reactor volume in which tohydrotreat materials. The hydrotreating conditions may allow thereaction to be run at low hydrogen partial pressures and/or at lowtemperatures (e.g., less than about 0.007 to about 1.4 bars or about0.14 to about 0.7 bars partial pressure hydrogen and/or about 200° C. toabout 450° C. or about 200° C. to about 250° C.). Coking within theformation generates hydrogen, which may be used for hydrotreating. Eventhough coke may be produced, coking may not cause a decrease in thethroughput of the formation because of the large pore volume of thereservoir.

[1856] The heated formation may have lower catalytic activity forhydrotreating compared to commercially available hydrotreatingcatalysts. The formation provides a long residence time, large volume,and large surface area, such that the process may be economical evenwith lower catalytic activity. In some formations, metals may bepresent. These naturally present metals may be incorporated into thecoke and provide some catalytic activity during hydrotreating.Advantageously, a stream generated or introduced into a hydrotreatingzone does not need to be monitored for the presence of catalystdeactivators or destroyers.

[1857] In an embodiment, the hydrotreated products produced from an insitu hydrotreating zone may include a hydrocarbon mixture and aninorganic mixture. The produced products may vary depending upon, forexample, the compound provided. Examples of products that may beproduced from an in situ hydrotreating process include, but are notlimited to, hydrocarbons, ammonia, hydrogen sulfide, water, or mixturesthereof. In some embodiments, ammonia, hydrogen sulfide, and/oroxygenated compounds may be less than about 40 weight % of the producedproducts.

[1858] In an in situ conversion process embodiment, a heated formationmay be used for separation processes. FIG. 273 illustrates an embodimentof a temperature gradient formed in a selected section of heatedformation 8501. Formation temperatures may decrease radially from heatsource 8500 through the selected section. A fluid (either products fromvarious surface processes and/or products from other sources such ascrude oil) may be provided through injection well 8502. The fluid maypass through heated formation 8501. Some production wells 8503 may belocated at various positions along the temperature gradient. For vaporphase production wells, different products may be produced fromproduction wells that are at different temperatures. The ability toproduce different compositions from production wells depending on thetemperature of the production well may allow for production of a desiredcomposition from selected wells based on boiling points of fluids withinthe formation. Some compounds with boiling points that are below thetemperature of a production well may be entrained in vapor and producedfrom the production well.

[1859]FIG. 274 illustrates an embodiment for separating hydrocarbonmixtures in a heated portion of formation 8506. Temperature and/orpressure of the heated portion may be controlled by heat source 8504. Ahydrocarbon mixture may be provided through injection well 8505 into aportion of the formation that is cooler than a portion of the formationcloser to heat sources or production wells. In a cooler portion offormation 8506, relatively heavy molecular weight products may condenseand remain in the formation. After separation of a desired quantity ofhydrocarbon mixture, the cooler portion of the formation may be heatedto result in pyrolysis of a portion of the heavy hydrocarbons to desiredproducts and/or mobilization of a portion of the heavy hydrocarbons toproduction well 8507.

[1860] In an embodiment, a portion of a formation may be shut in atselected times to provide control of residence time of the products inthe subsurface formation. Shutting in a portion of the formation by notproducing fluid from production wells may result in an increase inpressure in the formation. The increased pressure may result inproduction of a lighter fluid from the formation when production isresumed. Different products may be produced based on the residence timeof fluids in the formation.

[1861] Once a formation has undergone an in situ conversion process,heat from the process may remain within the formation. Heat may berecovered from the formation using a heat transfer fluid. Heat transferfluids used to recover energy from an oil shale formation may include,but are not limited to, formation fluids, product streams (e.g., ahydrocarbon stream produced from crude oil introduced into theformation), inert gases, hydrocarbons, liquid water, and/or steam. FIG.275 illustrates an embodiment for recovering heat remaining in formation8509 by providing a product stream through injection well 8510. Heatremaining in the formation may transfer to the product stream. Theformation heat may be controlled with heat source 8508. The heatedproduct stream may be produced from the formation through productionwell 8511. The heat of the product stream may be transferred to anynumber of surface treatment units 8512 or to other formations.

[1862] In an in situ conversion process embodiment, heat recovered fromthe formation by a heat transfer fluid may be directed to surfacetreatment units to utilize the heat. For example, a heat transfer fluidmay flow to a steam-cracking unit. The heat transfer fluid may passthrough a heat exchange mechanism of the steam-cracking unit to transferheat from the heat transfer fluid to the steam-cracking unit. Thetransferred heat may be used to vaporize water or as a source of heatfor the steam-cracking unit.

[1863] In some in situ conversion process embodiments, heat transferfluid may be used to transfer heat to a hydrotreating unit. The heattransfer fluid may pass through a heat exchange mechanism of thehydrotreating unit. Heat from the product stream may be transferred fromthe heat transfer fluid to the hydrotreating unit. Alternatively, atemperature of the heat transfer fluid may be increased with a heatingunit prior to processing the heat transfer fluid in a steam crackingunit or hydrotreating unit. In addition, heat of a heat transfer fluidmay be transferred to any other type of unit (e.g., distillation column,separator, regeneration unit for an activated carbon bed, etc.).

[1864] Heat from a heated formation may be recovered for use in heatinganother formation. FIG. 276 illustrates an embodiment of a heat transferfluid provided through injection well 8515 into heated formation 8514.Heat may transfer from the heated formation to the heat transfer fluid.Heat source 8513 may be used to control formation heat. The heattransfer fluid may be produced from production well 8516. The heattransfer fluid may be directed through injection well 8517 to transferheat from the heat transfer fluid to formation 8518. Formationconditions subsequent to an in situ conversion process may determine theheat transfer fluid temperature. The heat transfer fluid may be producedfrom production well 8519. In some embodiments, formation 8518 mayinclude U-tube wells or closed casings with fluid insertion ports andfluid removal ports so that heat transfer fluid does not enter into therock of the formation.

[1865] Movement of the heat transfer fluid (e.g., product streams, inertgas, steam, and/or hydrocarbons) through the formation may be controlledsuch that any associated hydrocarbons in the formation are directedtowards the production wells. The formation heat and mass transfer ofthe heat transfer fluid may be controlled such that fluids within theformation are swept towards the production wells. During remediation ofa formation, the formation heat and mass transfer of the heat transferfluid may be controlled such that transfer of heat from the formation tothe heat transfer fluid is accomplished simultaneously with clean up ofthe formation.

[1866]FIG. 277 illustrates an in situ conversion process embodiment inwhich a heat transfer fluid is provided to formation 8521 a throughinjection well 8522. Heat within formation 8521 a may be controlled byheat source 8520. The heat of the heat transfer fluid may be transferredto cooler formation 8521 b. The heat transfer fluid may be producedthrough production well 8523. In other embodiments, a heat transferfluid may be directed to a plurality of formations to heat the pluralityof formations.

[1867]FIG. 278 illustrates an embodiment for controlling formation 8525a to produce region of reaction 8525 b in the formation. A region ofreaction may be any section of the formation having a temperaturesufficient for a reaction to occur. A region of reaction may be hotteror cooler than a portion of a formation proximate the region ofreaction. Material may be directed to the region of reaction throughinjection well 8526. The material may be reacted within the region ofreaction. Any number and any type of heat source 8524 may heat theformation and the region of reaction. Appropriate heat sources include,but are not limited to, electric heaters, surface burners, flamelessdistributed combustors, and/or natural distributed combustors. Theproduct may be produced through production well 8527.

[1868] In some in situ conversion process embodiments, a region ofreaction may be heated by transference of heat from a heated product tothe region of reaction. In some embodiments, regions of reaction may bein series. A material may flow through the regions of reaction in aserial manner. The regions of reaction may have substantially the sameproperties. As such, flowing a material through such regions of reactionmay increase a residence time of the material in the regions ofreaction. Alternatively, the regions of reaction may have differentproperties (e.g., temperature, pressure, and hydrogen content). Flowinga material through such regions of reaction may include performingseveral different reactions with the material. Various materials may bereacted in a region of reaction. Examples of such materials include, butare not limited to, materials produced by an in situ conversion processand hydrocarbons produced from petroleum crude (e.g., tar, pitch,asphaltenes, heavy hydrocarbons, naphtha, methane, ethane, propane,and/or butane).

[1869] In some in situ conversion process embodiments, a region ofreaction may be formed by placing conduit 8530 in a heated portion offormation 8529. FIG. 279 depicts such an embodiment of an in situconversion process. A portion of conduit 8530 may be heated by theformation to form a region of reaction within the conduit. The conduitmay inhibit contact between the material and the formation. Theformation temperature and conduit temperature may be controlled by heatsource 8528. Material may be provided through injection well 8531. Thematerial may be produced through production well 8532.

[1870] A shape of a conduit may be variable. For example, the conduitmay be curved, straight, or U-shaped (as shown in FIG. 280). U-shapedconduit 8534 may be placed within a heater well in a heated formation.Any number of materials may be reacted within the conduit. For example,water may be passed through a conduit such that the water is heated to atemperature higher than the initial water temperature. In otherembodiments, water may be heated in a conduit to produce steam. Materialmay be provided through injection site 8535 and produced throughproduction site 8536. The formation temperature may be controlled byheat source 8533.

[1871] In some in situ conversion process embodiments, formations may beused to store materials. A first portion of a formation may be subjectedto in situ conversion. After in situ conversion, the first portion maybe permeable and have a large pore volume. Formation fluid (e.g.,pyrolysis fluid or synthesis gas) produced from another portion of theformation may be stored in the first portion. Alternately, the firstportion may be used to store a separated component of formation fluidproduced from the formation, a compressed gas (e.g., air), crude oil,water, or other fluid. Alternately, the first portion may be used tostore carbon dioxide or other fluid that is to be sequestered.

[1872] Materials may be stored in a portion of the formation temporarilyor for long periods of time. The materials may include inorganic and/ororganic compounds and may be in solid, liquid, and/or gaseous form. Ifthe materials are solids, the solid products may be stored as a liquidby dissolving the materials in a suitable solvent. If the materials areliquids or gases, they may be stored in such form. The materials may beproduced from the formation when needed. In some storage embodiments,the stored material may be removed from the formation by heating theformation using heat sources inserted in wellbores in the formation andproducing the stored material from production wells. The heat sourcesmay be heat sources used during a pyrolysis and/or synthesis gasgeneration phase of the in situ conversion process. The production wellsmay be production wells used during the pyrolysis and/or synthesis gasgeneration phase of the in situ conversion process. In otherembodiments, the heat source and/or production wells may be wells thatwere originally used for a different purpose and converted to a newpurpose. In some embodiments, some or all heat source and/or productionwells may be newly formed wells in the storage portion of the formation.

[1873] In a storage process embodiment, oil may be stored in a portionof a formation that has been subjected to an in situ conversion process.In some embodiments, natural gas may be stored in a portion of aformation that has been subjected to an in situ conversion process. Ifthe formation is close to the surface, the shallow depth of theformation may limit gas pressure. In certain embodiments, close spacingof wells may provide for rapid recovery of oil and/or natural gas withhigh efficiency.

[1874] In a storage process embodiment, compressed air may be stored ina portion of a formation that has been subjected to an in situconversion process. The stored compressed air may be used for peak powergeneration, load leveling, and/or to even out and compensate for thevariability of renewable power sources (e.g., solar and/or wind power).A portion of the stored compressed air may be used as an oxygen sourcefor a natural distributed combustor, flameless distributed combustor,and/or a surface burner.

[1875] In an in situ conversion process embodiment, water may beprovided to a hot formation to produce steam. The water may be appliedduring pyrolysis to help remove coke adjacent to or on heat sourcesand/or production wells. Water may also be introduced into the formationafter pyrolysis and/or synthesis gas generation is complete. Theproduced steam may sweep hydrocarbons towards production wells. Theformation heat transfer and mass transfer may be controlled to clean theformation during recovery of heat from the formation. The introducedwater may absorb heat from the formation as the water is transformed tosteam, resulting in cooling of the formation. The steam may be producedfrom the formation. Organic or other components in the steam may beseparated from the steam and/or water condensed from the steam. Thesteam may be used as a heat transfer fluid in a separation unit or inanother portion of the formation that is being heated. Cleaned orfiltered water may be produced along with subsequent cooling of theformation.

[1876] In an in situ conversion process embodiment, a hot formation maytreat water to remove dissolved cations (e.g., calcium and/or magnesiumions). The untreated water may be converted to steam in the formation.The steam may be produced and condensed to provide softened water (e.g.,water from which calcium and magnesium salts have been removed). Ifadditional water is provided to the formation, the retained salts in theformation may dissolve in the water and “hard” water may be produced.Therefore, order of treatment may be a factor in water purificationwithin a formation. A hot formation may sterilize introduced water bydestroying microbes.

[1877] In certain embodiments, a cooled formation may be used as a largeactivated carbon bed. After pyrolysis and/or synthesis gas generation atreated, cooled formation may be permeable and may include a significantweight percentage of char/coke. The formation may be substantiallyuniformly permeable without significant fluid passage fractures fromwellbore to wellbore within the formation. Contaminated water may beprovided to the cooled formation. The water may pass through the cooledformation to a production well. Material (e.g., hydrocarbons or metalcations) may be adsorbed onto carbon in the cooled formation, therebycleaning the water. In some embodiments, the formation may be used as afilter to remove microbes from the provided water. The filtrationcapability of the formation may depend upon the pore size distributionof the formation.

[1878] A treated portion of formation may be used trap and filter outparticulates. Water with particulates may be introduced into a firstwellbore. Water may be produced from production wells. When theparticulate matter clogs the pore space adjacent to the first wellboresufficiently to inhibit further introduction of water with particulates,the water with particulates may be introduced into a different wellbore.A large number of wellbores in a formation subject to in situ treatmentmay provide an opportunity to purify a large volume of water and/orstore a large amount of particulate matter in a formation.

[1879] Water quality may be improved using a heated formation. Forexample, after pyrolysis (and/or synthesis gas generation) is completed,formation water that was inhibited from passing into the formationduring conversion by freeze wells or other types of barriers may beallowed to pass through the spent formation. The formation water may bepassed through a hot formation to form steam and soften the water (i.e.,ionic compounds are not present in significant amounts in the producedsteam). The steam produced from the formation may be condensed to formformation water. The formation water may be passed through a carbon bed(in a surface facility or in a cooled, spent portion of the formation)to treat the formation water by adsorption, absorption, and/orfiltering.

[1880]FIG. 281 illustrates an embodiment for sequestering carbon dioxideas carbonate compounds in a portion of a formation. The carbon dioxidemay be sequestered in the formation by forming carbonate compounds fromthe carbon dioxide through carbonation reactions with pore water. Energyinput into heat sources 8537 may be used to control a temperature of theheated portion of formation 8540. Valves may be used to control apressure of the heated portion of the formation. In other embodiments,carbon dioxide may be sequestered in a cooled formation by adsorbing thecarbon dioxide on carbon than remains in the formation.

[1881] In the embodiment depicted in FIG. 281, solution 8538 is providedto the lower portion of the formation through well 8541 into dippingformation 8540. The solution may be obtained, for example, from naturalgroundwater flow or from an aquifer in a deeper formation. In anembodiment, the solution may be seawater. In some embodiments, the saltcontent of the water may be concentrated by evaporation. In certainembodiments, the solution may be obtained from man-made industrialsolutions (e.g., slaked lime solution) or agricultural runoff. Thesolution may include sodium, magnesium, calcium, iron, manganese, and/orother dissolved ions. Furthermore, the solution may contact the ash fromthe spent formation as it is provided to the post treatment formation.Contact of the solution with the formation ash may produce a buffered,basic solution.

[1882] In some sequestration embodiments, carbon dioxide 8539 may beprovided to the upper portion of the formation through well 8542simultaneously with providing solution 8538 to the formation. Thesolution may be provided to the lower portion of the formation, suchthat the solution rises through a portion of the provided carbondioxide. Carbonate compounds may form in a dissolution zone at theinterface of the solution and the carbon dioxide. In certainembodiments, the carbonate compounds may form by the reaction of thebasic solution with the carbonic acid produced when the carbon dioxidedissolves in the solution. Other mechanisms, however, may also cause theformation and precipitation of the carbonate compounds.

[1883] The type of carbonate compounds formed may be determined by thedissolved ions in the solution. Examples of carbonate compounds include,but are not limited to, calcite (CaCO₃), magnesite (MgCO₃), siderite(FeCO₃), rhodochrosite (MnCO₃), ankerite (CaFe(CO₃)₂), dolomite(CaMg(CO₃)₂), ferroan dolomite, magnesium ankerite, nahcolite (NaHCO₃),dawsonite (NaAl(OH)₂CO₃), and/or mixtures thereof. Other carbonatecompounds that may be precipitated include, but are not limited to,cerussite (PbCO₃), malachite (Cu₂(OH)₂CO₃, azurite (Cu₃(OH)₂(CO₃)₂),smithsonite (ZnCO₃), witherite (BaCO₃), strontianite (SrCO₃), and/ormixtures thereof.

[1884] A portion of the solution may be slowly withdrawn from theformation to deposit carbonate compounds within the formation. Afterwithdrawal, the solution may be reinserted into the formation tocontinue precipitation of carbonate compounds in the formation. Thesolution may rise again through the provided carbon dioxide andadditional carbonates may be formed and precipitated. The solution maybe cycled up and down within the formation to maximize the precipitationof carbonates within the formation. The carbonate compounds may remainwithin the formation.

[1885] In an embodiment, chemical compounds (e.g., CaO) may be added tothe solution if the amount of ash remaining in the formation isinsufficient to provide adequate buffering. In some embodiments,chemical compounds may be added to surface water to produce a solution.

[1886] Altering the pH of a solution in which carbon dioxide isdissolved may allow carbonate formation. Compounds that hydrolyze indifferent temperature ranges to produce basic compounds may be includedin the solution. Therefore, altering the solution temperature may alterthe solution pH, thus allowing carbonate formation. Compounds thathydrolyze to produce basic compounds may include cyanates and nitrites.Examples of cyanates and nitrites may include, but are not limited to,potassium cyanate, sodium cyanate, sodium nitrite, potassium nitrite,and/or calcium nitrite. In some embodiments, urea may also hydrolyze toproduce a basic compound.

[1887] In a sequestration embodiment, carbon dioxide may be allowed todiffuse throughout a solution within a formation. The solution mayinclude at least one of the compounds that hydrolyze. The formation maybe heated such that the compound(s) included in the solution hydrolyzesand produces a basic solution. The carbonate compounds may precipitatewhen appropriate ions (e.g., calcium and/or magnesium) are present.Altering the solution temperature may provide an ability to alter theoccurrence and rate of carbonate precipitation in the formation. Heatmay be provided from heat sources in the formation.

[1888] In a sequestration embodiment, carbon dioxide may be provided toa dipping formation. A solution may be provided to the dipping formationso that the solution contacts carbon dioxide to allow for precipitationof carbonate in the formation. Carbon dioxide and/or solution additionmay be cycled to increase the amount of carbonate formed in theformation.

[1889] Formation of carbonate compounds may inhibit movement of mobileor released hydrocarbon compounds to groundwater. Formation of carbonatecompounds may decrease the permeability of the formation and inhibitwater or other fluid from migrating into or out of a portion of theformation in which carbonates have been formed. Formation of carbonatesmay decrease leaching of metals in the formation to groundwater,decrease formation deformation, and/or decrease well damage by providingsupport for the remaining formation overburden. In certain in situconversion process embodiments, the formation of carbonate compounds maybe a part of the abandonment and reclamation process for the formation.

[1890] In an embodiment, heating during in situ conversion processes maycause decomposition of calcite (limestone) or dolomite to lime andmagnesite. Upon carbonation, the calcite and dolomite may bereconstituted. The reconstitution may result in sequestration of asignificant volume of carbon dioxide.

[1891] In a sequestration embodiment, existing wellbores may be usedduring formation of carbonates in the formation. A solution may beprovided to the formation and recovery of the solution may be providedfrom adjacent or closely spaced wells to create small circulation cells.In some embodiments with a dipping or thick formation, a counterflow ofcarbon dioxide and water may be applied. The carbon dioxide may beprovided downdip (e.g., a point lower in the formation) and the solutionprovided updip (e.g., a point higher in the formation). The carbondioxide and the solution may migrate past each other in a counterflowmanner. In other embodiments, the carbon dioxide may be bubbled upthrough a solution-filled formation.

[1892] In a sequestration embodiment, precipitation of mineral phases(e.g., carbonates) may cement together the friable and unconsolidatedformation matrix remaining after an in situ conversion process. Incertain embodiments, the formation of minerals in an in situ formationmay be similar to natural mineral formation and cementation, thoughsignificantly accelerated.

[1893] In an embodiment, vertical and/or horizontal mineral formationnear a well may provide at least some well integrity. Mineralprecipitation may provide the formation around the well with highercohesiveness and strength. The increased cohesiveness and strength mayinhibit compaction and deformation of the formation around the wellbore.

[1894] In some in situ conversion process embodiments, non-hydrocarbonmaterials such as minerals, metals, and other economically viablematerials contained within the formation may be economically producedfrom the formation. In some embodiments, the non-hydrocarbon materialsmay be mined or extracted from the formation following an in situconversion process. However, mining or extracting material following anin situ conversion process may not be economically or environmentallyfavorable. In certain embodiments, non-hydrocarbon materials may berecovered and/or produced prior to, during, and/or after the in situconversion process for treating hydrocarbons using an additional in situprocess of treating the formation for producing the non-hydrocarbonmaterials.

[1895] In an embodiment for producing non-hydrocarbon material, aportion of the formation may be subjected to in situ conversion processto produce hydrocarbons and/or synthesis gas from the formation. Thetemperature of the portion may be reduced below the boiling point ofwater at formation conditions. A first fluid may be injected into theportion. The first fluid may be injected through a production well,heater well, or injection well. The first fluid may include an agentthat reduces, mixes, combines, or forms a solution with non-hydrocarbonmaterials to be recovered. The first fluid may be water, a basicsolution, an acid solution, and/or a hydrocarbon fluid. In someembodiments, the first fluid may be introduced into the formation as ahot or warm liquid. The first fluid may be heated using heat generatedin another portion of the formation and/or using excess heat fromanother portion of the formation.

[1896] A second fluid may be produced in the formation from formationmaterial and the first fluid. The second fluid may be produced from theformation through production wells. The second fluid may include desirednon-hydrocarbon materials from the formation. The non-hydrocarbonmaterials may include valuable metals such as, but not limited to,aluminum, nickel, vanadium, and gold. The non-hydrocarbon materials mayalso include minerals that contain phosphorus, sodium, or magnesium. Incertain embodiments, the second fluid may include metals combined withminerals. For example, the second fluid may contain phosphates,carbonates, etc. Metals, minerals, or other non-hydrocarbon materialscontained within the second fluid may be produced or extracted from thesecond fluid.

[1897] Producing the non-hydrocarbon materials may include separatingthe materials from the solution mixture. Producing the non-hydrocarbonmaterials may include processing the second fluid in a surface facilityor refinery. In some embodiments, the first fluid may be circulatedthrough the formation from an injection well to a removal site of thesecond fluid. Any portion of the first fluid remaining in the secondfluid may be recirculated (or re-injected) into the formation as aportion of the first fluid. In other embodiments, the second fluid maybe treated at the surface to remove non-hydrocarbon materials from thesecond fluid. This may reconstitute the first fluid from the secondfluid. The reconstituted first fluid may be re-injected into theformation for further material recovery.

[1898] In certain embodiments, a first fluid may be injected into aportion of the formation that has been treated using an in situconversion process. The first fluid may include water. The first fluidmay break and/or fragment the formation into relatively small pieces ofmineral matrix containing hydrocarbons. The relatively small pieces maycombine with the first fluid to form a slurry. The slurry may be removedor produced from the formation. The slurry may be treated in a surfacefacility to separate the first fluid from the relatively small pieces ofhydrocarbons. The mineral matrix containing hydrocarbon pieces may betreated in a refining or extraction process in a surface facility.

[1899] In some embodiments, non-hydrocarbon materials may be producedfrom a formation prior to treating the formation in situ. Heat may beprovided to the formation from heat sources. The formation may reach anaverage temperature approaching below pyrolysis temperatures (e.g.,about 260° C. or less). A first fluid may be injected into theformation. The first fluid may dissolve and or entrain formationmaterial to form a second fluid. The second fluid may be produced fromthe formation.

[1900] Some oil shale formations may include nahcolite, trona, and/ordawsonite within the formation. For example, nahcolite may be containedin unleached portions of a formation. Unleached portions of a formationare parts of the formation where groundwater has not leached outminerals within the formation. For example, in the Piceance basin inColorado, unleached oil shale is found below a depth of about 500 mbelow grade. Deep unleached oil shale formations in the Piceance basincenter tend to be rich in hydrocarbons. For example, about 0.10 litersof oil per kilogram (L/kg) of oil shale to about 0.15 L/kg of oil shalemay be producible from an unleached oil shale formation.

[1901] Nahcolite is a mineral that includes sodium bicarbonate (NaHCO₃).Nahcolite may be found in formations in the Green River lakebeds inColorado, USA. Greater than about 5 weight %, and in some embodimentseven greater than about 10 weight %, or greater than about 20 weight %nahcolite may be present in a formation. Dawsonite is a mineral thatincludes sodium aluminum carbonate (NaAl(CO₃)(OH)₂). Dawsonite may bepresent in a formation at weight percents greater than about 2 weight %or, in some embodiments, greater than about 5 weight %. The nahcoliteand/or dawsonite may dissociate at temperatures used in an in situconversion process of treating a formation. The dissociation is stronglyendothermic and may produce large amounts of carbon dioxide. Thenahcolite and/or dawsonite may be solution mined prior to, during,and/or following treating a formation in situ to avoid the dissociationreactions. For example, hot water may-be used to form a solution withnahcolite. Nahcolite may form sodium ions (Na⁺) and bicarbonate ions(HCO₃ ⁻) in aqueous solution. The solution may be produced from theformation through production wells.

[1902] A formation that includes nahcolite and/or dawsonite may betreated using an in situ conversion process. A perimeter barrier may beformed around the portion of the formation to be treated. The perimeterbarrier may inhibit migration of water into the treatment area. Duringan in situ conversion process, the perimeter barrier may inhibitmigration of dissolved minerals and formation fluid from the treatmentarea. During initial heating, a portion of the formation to be treatedmay be raised to a temperature below the disassociation temperature ofthe nahcolite. The first temperature may be less than about 90° C., orin some embodiments, less than about 80° C. The first temperature maybe, however, any temperature that increases a reaction of a solutionwith nahcolite, but is also below a temperature at which nahcolite maydissociate (above about 95° C. at atmospheric pressure). A first fluidmay be injected into the heated portion. The first fluid may includewater, steam, or other fluids that may form a solution with nahcoliteand/or dawsonite. The first fluid may be at an increased temperature(e.g., about 90° C. or about 100° C.). The increased temperature may besubstantially similar to the first temperature of the portion of theformation.

[1903] In some embodiments, the portion of the formation may be atambient temperature and the first fluid may be injected at an increasedtemperature. The increased temperature may be a temperature below aboiling point of the first fluid (e.g., about 90° C. for water).Providing the first fluid at an increased temperature may increase atemperature of a portion of the formation. Additional heat may beprovided from one or more heat sources (e.g., a heater in a heater well)placed in the formation.

[1904] In other embodiments, steam is included in the first fluid. Heatfrom the injection of steam into the formation may be used to provideheat to the formation. The steam may be produced from recovered heatfrom the formation (e.g., from steam recovered during remediation of aportion) or from heat exchange with formation fluids and/or with surfacefacilities.

[1905] A second fluid may be produced from the formation followinginjection of the first fluid into the formation. The second fluid mayinclude products of injection of the first fluid into the formation. Forexample, the second fluid may include carbonic acid or other hydratedcarbonate compounds formed from the dissolution of nahcolite in thefirst fluid. The second fluid may also include minerals and/or metals.The minerals and/or metals may include sodium, aluminum, phosphorus, andother elements. Producing the second fluid from the formation may reducean amount of carbon dioxide produced from the formation during an insitu conversion process. Reducing the amount of carbon dioxide may beadvantageous because the production of carbon dioxide from nahcolite isendothermic and uses significant amounts of energy. For example,nahcolite has a heat of decomposition of about 0.66 joules per kilogram(J/kg). The energy required to pyrolyze hydrocarbons in a formationusing an in situ process may generally be about 0.35 J/kg. Thus, todecompose nahcolite from a formation having about 20 weight % nahcolite,about 0.13 J/kg additional energy would be needed. Removing nahcolitefrom a formation using a solution mining process prior to treating theformation using an in situ conversion process may significantly reducecarbon dioxide emissions from the formation as well as energy requiredto heat the formation.

[1906] Some minerals (e.g., trona, pirssonite, or gaylussite) mayinclude associated water. Solution mining, or removing, such mineralsbefore heating the formation may reduce costs of heating the formationto pyrolysis temperatures since associated water is removed prior toheating of the formation. Thus, the heat for dissociation of water fromthe mineral does not have to be provided to the formation.

[1907]FIG. 282 depicts an embodiment for solution mining a formation.Barrier 6500 (e.g., a frozen barrier) may be formed around acircumference of treatment area 6510 of the formation. Barrier 6500 maybe any barrier formed to inhibit a flow of water into or out oftreatment area 6510. For example, barrier 6500 may include one or morefreeze wells that inhibit a flow of water through the barrier. In someembodiments, barrier 6500 has a diameter of about 18 m. Barrier 6500 maybe formed using one or more barrier wells 6502. Barrier wells 6502 mayhave a spacing of about 2.4 m. Formation of barrier 6500 may bemonitored using monitor wells 6504 and/or by monitoring devices placedin barrier wells 6502.

[1908] Water inside treatment area 6510 may be pumped out of thetreatment area through production well 6516. Water may be pumped until aproduction rate of water is low. Heat may be provided to treatment area6510 through heater wells 6514. The provided heat may heat treatmentarea 6510 to a temperature of about 90° C. or, in some embodiments, to atemperature of about 100° C., 110° C., or 120° C. A temperature oftreatment area 6510 may be monitored using temperature measurementdevices placed in temperature wells 6518.

[1909] A first fluid (e.g., water) may be injected through one or moreinjection wells 6512. The first fluid may also be injected through aheater or production well located in the formation. The first fluid maymix and/or combine with non-hydrocarbon materials (e.g., minerals,metals, nahcolite, and dawsonite) that are soluble in the first fluid toproduce a second fluid. The second fluid, containing the non-hydrocarbonmaterials, may be removed from the treatment area through productionwell 6516 and/or heater wells 6514. Production well 6516 and heaterwells 6514 may be heated during removal of the second fluid. Afterproducing a majority of the non-hydrocarbon materials from treatmentarea 6510, solution remaining within the treatment area may be removed(e.g., by pumping) from the treatment area through production well 6516and/or heater wells 6514. A relatively high permeability treatment area6510 may be produced following removal of the non-hydrocarbon materialsfrom the treatment area.

[1910] Hydrocarbons within treatment area 6510 may be pyrolyzed and/orproduced using an in situ conversion process of treating a formationfollowing removal of the non-hydrocarbon materials. Heat may be providedto treatment area 6510 through heater wells 6514. A mixture ofhydrocarbons may be produced from the formation through production well6516 and/or heater wells 6514.

[1911] In certain embodiments, during an initial heating up to atemperature near a boiling temperature of water, unleached solubleminerals within the formation may be disaggregated and dissolved inwater condensing within the formation. The water may be condensing incooler portions of the formation. Some of these minerals may flow in thecondensed water to production wells. The water and minerals are producedthrough the production wells.

[1912] Following an in situ conversion process, treatment area 6510 maybe cooled during heat recovery by introduction of water to produce steamfrom a hot portion of the formation. Introduction of water to producesteam may vaporize some hydrocarbons remaining in the formation. Watermay be injected through injection wells 6512. The injected water maycool the formation. The remaining hydrocarbons and generated steam maybe produced through production wells 6516 and/or heater wells 6514.Treatment area 6510 may be cooled to a temperature near the boilingpoint of water.

[1913] Treatment area 6510 may be further cooled to a temperature atwhich water will begin to condense within the formation (i.e., atemperature below a boiling temperature of water). Removing the water orother solvents from treatment area 6510 may also remove any materialsremaining in the treatment area that are soluble in water. The water maybe pumped out of treatment area 6510 through production well 6516 and/orheater wells 6514. Additional water and/or other solvents may beinjected into treatment area 6510. This injection and removal of watermay be repeated until a sufficient water quality within treatment area6510 is reached. Water quality may be measured at injection wells 6512,heater wells 6514, and/or production wells 6516. The sufficient waterquality may be a water quality that substantially matches a waterquality of treatment area 6510 prior to treatment.

[1914] In some embodiments, treatment area 6510 may include a leachedzone located above an unleached zone. The leached zone may have beenleached naturally and/or by a separate leaching process. In certainembodiments, the unleached zone may be at a depth of about 500 m. Athickness of the unleached zone may be about 100 m to about 500 m.However, the depth and thickness of the unleached zone may varydepending on, for example, a location of treatment area 6510 and a typeof formation. A first fluid may be injected into the unleached zonebelow the leached zone. Heat may also be provided into the unleachedzone.

[1915] In certain embodiments, a section of a formation may be leftunleached or without injection of a solution. The unleached section maybe proximate a selected section of the formation that has been leachedby providing a first fluid as described above. The unleached section mayinhibit the flow of water into the selected section. In someembodiments, more than one unleached section may be proximate a selectedsection.

[1916] In an embodiment, a formation may contain both nahcolite and/ordawsonite. For example, oil shale formations within the Green Riverlakebeds in the U.S. Piceance Basin contain nahcolite and dawsonite inaddition to kerogen. Nahcolite, hydrocarbons, and alumina (fromdawsonite) may be produced from these types of formations.

[1917] Water may be injected into the formation through a heater well oran injection well. The water may be heated and/or injected as steam. Thewater may be injected at a temperature at or near the decompositiontemperature of nahcolite. For example, the water may be at a temperatureof about 70° C., 90° C., 100° C., or 110° C. Nahcolite within theformation may form an aqueous solution following the injection of water.The aqueous solution may be removed from the formation through a heaterwell, injection well, or production well. Removing the nahcolite removesmaterial that would otherwise form carbon dioxide during heating of theformation to pyrolysis temperature. Removing the nahcolite may alsoinhibit the endothermic dissociation of nahcolite during an in situconversion process. Removing the nahcolite may reduce mass within theformation and increase a permeability of the formation. Reducing themass within the formation may reduce the heat required to heat totemperatures needed for the in situ conversion process. Reducing themass within the formation may also increase a speed at which a heatfront within the formation moves. Increasing the speed of the heat frontmay reduce a time needed for production to begin. In some embodiments,slightly higher temperatures may be used in the formation (e.g., aboveabout 120° C.) and the nahcolite may begin to decompose. In such a case,nahcolite may be removed from the formation as a soda ash (Na₂CO₃).

[1918] Nahcolite removed from the formation may be heated in a surfacefacility to form sodium carbonate and/or sodium carbonate brine. Heatingnahcolite will form sodium carbonate according to the equation:

2NaHCO₃→Na₂CO₃+CO₂+H₂O.  (60)

[1919] The sodium carbonate brine may be used to solution mine alumina.The carbon dioxide produced may be used to precipitate alumina. If sodaash is produced from solution mining of nahcolite, the soda ash may betransported to a separate facility for treatment. The soda ash may betransported through a pipeline to the separate facility.

[1920] Following removal of nahcolite from the formation, the formationmay be treated using an in situ conversion process to producehydrocarbon fluids from the formation. Remaining water is drained fromthe solution mining area through dewatering wells prior to heating to insitu conversion process temperatures. During the in situ conversionprocess, a portion of the dawsonite within the formation may decompose.Dawsonite will typically decompose at temperatures above about 270° C.according to the reaction:

2NaAl(OH)₂CO₃→Na₂CO₃+Al₂O₃+2H₂O+CO₂.  (61)

[1921] The alumina formed from EQN. 61 will tend to be in the form ofchi alumina. Chi alumina is relatively soluble in basic fluids.

[1922] Alumina within the formation may be solution mined using arelatively basic fluid following reaching pyrolysis temperatures ofhydrocarbons within the formation. For example, a dilute sodiumcarbonate brine, such as 0.5 Normal Na₂CO₃, may be used to solution minealumina. The sodium carbonate brine may be obtained from solution miningthe nahcolite. Obtaining the basic fluid by solution mining thenahcolite may significantly reduce costs associated with obtaining thebasic fluid. The basic fluid may be injected into the formation througha heater well and/or an injection well. The basic fluid may form analumina solution that may be removed from the formation. The aluminasolution may be removed through a heater well, injection well, orproduction well. An excess of basic fluid may have to be maintainedthroughout an alumina solution mining process.

[1923] Alumina may be extracted from the alumina solution in a surfacefacility. In an embodiment, carbon dioxide may be bubbled through thealumina solution to precipitate the alumina from the basic fluid. Carbondioxide may be obtained from the in situ conversion process or fromdecomposition of the dawsonite during the in situ conversion process.

[1924] In certain embodiments, a formation may include portions that aresignificantly rich in either nahcolite or dawsonite only. For example, aformation may contain significant amounts of nahcolite (e.g., greaterthan about 20 weight %) in a depocenter of the formation. The depocentermay contain only about 5 weight % or less dawsonite on average. However,in bottom layers of the formation, a weight percent of dawsonite may beabout 10 weight % or even as high as about 25 weight %. In suchformations, it may be advantageous to solution mine for nahcolite onlyin nahcolite-rich areas, such as the depocenter, and solution mine fordawsonite only in the dawsonite-rich areas, such as the bottom layers.This selective solution mining may significantly reduce a fluid cost,heating cost, and/or equipment cost associated with operating a solutionmining process.

[1925] Nordstrandite (Al(OH)₃) is another aluminum bearing mineral thatmay be found in a formation. Nordstrandite decomposes at about the sametemperatures (about 300° C.) as dawsonite and will produce aluminaaccording to the equation:

2Al(OH)₃Al₂O₃+3H₂O.  (62)

[1926] Nordstrandite is typically found in formations that also containdawsonite and may be solution mined simultaneously with the dawsonite.

[1927] Solution mining dawsonite and nahcolite may be a simple processthat produces only aluminum and soda ash from a formation. It may bepossible to use some or all hydrocarbons produced from an in situconversion process to produce direct current (DC) electricity on a siteof the formation. The produced DC electricity may be used on the site toproduce aluminum metal from the alumina using the Hall process. Aluminummetal may be produced from the alumina by melting the alumina in asurface facility on the site. Generating the DC electricity at the sitemay save on costs associated with using hydrotreaters, pipelines, orother surface facilities associated with transporting and/or treatinghydrocarbons produced from the formation using the in situ conversionprocess.

[1928] Some formations may also contain amounts of trona. Trona is asodium sesquicarbonate (Na₂CO₃.NaHCO₃.2H₂O) that has properties andundergoes reactions (including decomposition) very similar to those ofnahcolite. Treatments for solution mining of trona may be substantiallysimilar to treatments used for solution mining of nahcolite. Trona maytypically be found in kerogen formations such as oil shale formations inWyoming.

[1929] For certain types of formations, solution mining may be used torecover non-hydrocarbon materials prior to heating the formation tohydrocarbon pyrolysis temperatures. Examples of such materials andformations may include nahcolite and dawsonite in Green River oil shale,trona in Wyoming oil shale, or ammonia from buddingtonite in the Condordeposit in Queensland, Australia. Other non-hydrocarbon materials thatmay be solution mined include carbonates (e.g., trona, eitelite,burbankite, shortite, pirssonite, gaylussite, norsethite,thermonatrite), phosphates, carbonate-phosphates (e.g., bradleyite),carbonate chlorides (e.g., northupite), silicates (e.g., albite,analcite, sepiolite, loughlinite, labuntsovite, acmite, elpidite,magnesioriebeckite, feldspar), borosilicates (e.g., reedmergnerite,searlesite, leucosphenite), and halides (e.g., neighborite, cryolite,halite). Solution mining prior to hydrocarbon pyrolysis may increase apermeability of the formation and/or improve other features (e.g.,porosity) of the formation for the in situ process. Solution mining mayalso remove significant portions of compounds that will tend toendothermically dissociate at increased temperatures. Removing theseendothermically dissociating compounds from the formation tends todecrease an amount of heat input required to heat the formation.

[1930] For some types of formations, it may be advantageous to solutionmine a formation after pyrolysis and/or synthesis gas production. Manydifferent types of non-hydrocarbon materials may be removed from aformation following an in situ conversion process.

[1931] For example, phosphate may be removed from marine oil shaleformations such as the Phosphoria formation in Idaho. Phosphate may havea weight percentage up to about 20 weight % or about 30 weight % inthese formations. Recovered phosphate may be used in combination withammonia and/or sulfur produced during the in situ conversion process toproduce useable materials such as fertilizer.

[1932] Metals may also be recoverable from marine oil shale deposits.Metals such as uranium, chromium, cobalt, nickel, gold, zinc, etc. maybe recovered from marine oil shale formations. Metals may also be foundin certain bitumen deposits. For example, bitumen deposits may containamounts of vanadium, nickel, uranium, platinum, or gold.

[1933] A simulation was used to predict the effects of solution miningnahcolite and dawsonite from an oil shale formation. The simulationpredicts the effect on oil production and energy requirements forproducing hydrocarbons from the oil shale formation using an in situconversion process. The kinetics of decomposition of nahcolite anddawsonite were used in the simulation.

[1934] Nahcolite decomposed into soda ash, carbon dioxide, and water.The frequency factor for the decomposition was 7.83×10¹⁵ (L/days). Theactivation energy was 1.015×10⁵ m joules per gram mole (J/gmol). Theheat of reaction was −62,072 J/gmol.

[1935] Dawsonite decomposed into soda ash plus alumina (Al₂O₃), carbondioxide, and water. The frequency factor for the decomposition was1.0×10²⁰ (L/days). The activation energy was 2.039×10⁵ J/gmol. The heatof reaction was −151,084 J/gmol.

[1936] The simulation assumed a 12.2 m well spacing in a triangularpattern. An injector well to producer well ratio was 12 to 1. FIG. 283illustrates cumulative oil production (m³) and cumulative heat input(kilojoules) versus time (years) using an in situ conversion process forsolution mined oil shale and for pre-solution mined oil shale. Curve6520 illustrates cumulative oil production for non-solution mined oilshale. Curve 6522 illustrates cumulative heat input for non-solutionmined oil shale. Curve 6524 illustrates cumulative oil shale productionfor solution mined oil shale. Curve 6526 illustrates cumulative heatinput for solution mined oil shale.

[1937] The non-solution mined oil shale was assumed to have a 0.125liters per kilogram (L/kg) Fischer Assay with 5% dawsonite and 20%nahcolite, a 1.9% fracture porosity, and a 65% water saturation. Thesolution mined oil shale was found to have a 0.125 L/kg Fischer Assaywith 5% dawsonite and 0% nahcolite, a 29% porosity (created from removalof the nahcolite), and a 1.5% water saturation. The solution mined oilshale was assumed to have a relatively high permeability, which reducesthe water saturation to 1.5%.

[1938] As shown in FIG. 283, the simulation predicts that oil productionin solution mined oil shale 6524 begins sooner and is faster than oilproduction in the non-solution mined oil shale 6520. For example, afterabout 9 years, solution mined oil shale has produced about 9500 m³ ofoil, while non-solution mined oil shale has only produced about 1500 m³of oil. Non-solution mined oil shale will produce about 9500 m³ of oilin about 12 years, 3 years later than solution mined oil shale.

[1939] Also, the simulation predicts that less heat is needed to produceoil from solution mined oil shale 6526 than from non-solution mined oilshale 6522. For example, after about 9 years, solution mined oil shalehas required about 9×10¹⁰ kJ of heat input, while non-solution mined oilshale has required about 1.1×10¹¹ kJ of heat input.

[1940] In certain embodiments a soluble compound (e.g., phosphates,bicarbonates, alumina, metals, minerals, etc.) may be produced from asoluble compound containing formation (e.g., a formation that containsnahcolite, dawsonite, nordstrandite, trona, carbonates,carbonate-phosphates, carbonate chlorides, silicates, borosililcates,etc.) that is different from an oil shale formation. For example, thesoluble compound containing formation may be adjacent (lower or higher)than the oil shale formation, or at different non-adjacent depths thanthe oil shale formation. In other embodiments, the soluble compoundcontaining formation may be located at a different geographic locationthan the oil shale formation.

[1941] In an embodiment, heat is provided from one or more heat sourcesto at least a portion of an oil shale formation. A mixture, at somepoint, may be produced from the formation. The mixture may includehydrocarbons from the formation as well as other compounds such as CO₂,H₂, etc. Heat from the formation, or heat from the mixture produced fromthe formation, may be used to adjust or change a quality of a firstfluid that is provided to the soluble compound containing formation.Heat may be provided in the form of hot water or steam produced from theformation. In other embodiments, heat may be transferred by heatexchangers to the first fluid. In other embodiments, a heated portion orcomponent from the mixture may be mixed with the first fluid to heat thefluid.

[1942] Alternately, or in addition, a component from the mixtureproduced from the oil shale formation may be used to adjust a quality ofa first fluid. For example, acidic compounds (e.g., carbonic acid,organic acids) or basic compounds (e.g., ammonium, carbonate, orhydroxide compounds) from the mixture produced from the oil shaleformation may be used to adjust the pH of the first fluid. For example,CO₂ from the oil shale formation may be used with water to acidify thefirst fluid. In certain embodiments, components added to the first fluid(e.g., divalent cations, pyridines, or organic acids such as carboxylicacids or naphthenic acids) may increase the solubility of the solublecompound in the first fluid.

[1943] Once adjusted (e.g., heated and/or changed by having at least onecomponent added to the first fluid), the first fluid may be injectedinto the soluble compound containing formation. The first fluid may, insome embodiments, include hot water or steam. The first fluid mayinteract with the soluble compound. The soluble compound may at leastpartially dissolve. A second fluid including the soluble compound may beproduced from the soluble compound containing formation. The solublecompound may be separated from the second fluid stream and treated orprocessed. Portions of the second fluid may be recycled into theformation.

[1944] In certain embodiments, heat from the oil shale formation maymigrate and heat at least a portion of the soluble compound containingformation. In some embodiments, the soluble compound containingformation may be substantially near, adjacent to, or intermixed with theoil shale formation. The heat that migrates may be useful to enhance thesolubility of the soluble compound when the first fluid is applied tothe soluble compound containing formation. Heat that migrates from theoil shale formation may be recovered instead of being lost.

[1945] Reusing openings (wellbores) for different applications may becost effective in certain embodiments. In some embodiments, openingsused for providing the heat sources (or from producing from the oilshale formation) may be used to provide the first fluid to the solublecompound containing formation or to produce the second fluid from thesoluble compound containing formation.

[1946] In certain embodiments, a solution may be first provided to, orproduced from, a formation in a solution mining operation. The solutionmay be provided or produced through openings. One or more of the sameopenings may later be used as heater wells or producer wells for an insitu conversion process. Additionally, one or more of the same openingsmay be used again for providing a first fluid to the same formationlayer or to a different formation layer. For example, the openings maybe used to solution mine components such as nahcolite. These openingsmay further be used as heater wells or producer wells in the oil shaleformation. Then the openings may be used to provide the first fluid toeither the hydrocarbon containing layer or a different layer at adifferent depth than the hydrocarbon containing layer. These openingsmay also be used when producing second fluid from the solution compoundcontaining formation.

[1947] Oil shale formations may have varied geometries and shapes.Conventional extraction techniques may not be appropriate for allformations. In some formations, rich hydrocarbon containing material maybe positioned in layers that are too thin to be economically extractedusing conventional methods. The rich oil shale formations typicallyoccur in beds having thicknesses between about 0.2 m and about 8 m.These rich oil shale formations may include, but are not limited to,kukersites, tasmanites, and similar high quality oil shales. Thehydrocarbon layers may yield from about 205 liters of oil per metric tonto about 1670 liters of oil per metric ton upon pyrolysis.

[1948]FIGS. 245 and 246 depict representations of embodiments of in situconversion process systems that may be used to produce a thin richhydrocarbon layer. To produce such layers, directionally drilled wellsmay be used to heat the thin hydrocarbon layer within the formation,plus a minimum amount of rock above and/or below. In some embodiments,the heat source wells may be placed in the rock above and/or below thethin hydrocarbon layer. The wells may be closely spaced to reduce heatlosses and speed the heating process. In addition, drilling technologiessuch as geosteering, slim well, coiled tubing, and other techniques maybe utilized to accurately and economically place the wells. Conductiveheat losses to the surrounding formation may be offset by a high oilcontent of the thin hydrocarbon layer, rapid heating of the thinhydrocarbon layer (e.g., a heating rate in the range of about 1° C./dayto about 15° C./day), and/or close spacing (meter scale) of heaters.Subsidence may be reduced, or even minimized, by positioning heaterwells in a non-hydrocarbon and/or lean section of the formationimmediately beneath and/or at the base of the thin hydrocarbon layer. Anon-hydrocarbon and/or lean section of the formation may lose lessmaterial than the thin hydrocarbon layer. Therefore, the structuralintegrity of formation may be maintained.

[1949] In some in situ conversion process embodiments, formations may betreated in situ by heating with a heat transfer fluid. A method fortreating a formation may include injecting a heat transfer fluid intothe formation. In some embodiments, steam may be used as the heattransfer fluid. The heat from the heat transfer fluid may transfer to aselected section of the formation. In conjunction with heat from heatsources, the heat may pyrolyze at least some of the hydrocarbons withinthe selected section of the formation. A vapor mixture that includespyrolysis products may be produced from the formation. The pyrolysisproducts may include hydrocarbons having an average API gravity of atleast about 25°. The vapor mixture may also include steam.

[1950] In one embodiment, hydrocarbons may be distilled from theformation. For example, hydrocarbons may be separated from the formationby steam distillation. The heat from the heat transfer fluid (e.g.,steam), and/or heat from heat sources, may vaporize some of thehydrocarbons within the selected section of the formation. The vaporizedhydrocarbons may include hydrocarbons having a carbon number greaterthan about 1 and a carbon number less than about 8. The vapor mixturemay include the vaporized hydrocarbons. In addition, coke, sulfur,nitrogen, oxygen, and/or metals may be separated from formation fluid inthe formation.

[1951] It may be advantageous to use steam injection for in situtreatment of oil shale formations. Substantially uniform heating of asubstantial portion of the hydrocarbons in a formation to pyrolysistemperatures with heat transfer from steam and heat sources (e.g.,electric heaters, gas burners, natural distributed combustors, etc.) maybe enhanced if the formation has relatively high permeability andhomogeneity. Relatively high permeability and homogeneity may allow theinjected steam to contact a large surface area within the formation.

[1952] In certain embodiments, in situ treatment of hydrocarbons may beaccomplished with a suitable combination of steam pressure, temperature,and residence time of injected steam, together with a selected amount ofheat from heat sources, at a selected depth in the formation. Forexample, at a temperature of about 350° C., at hydrostatic pressure, andat a depth of about 700 m to about 1000 m, a residence time of at leastapproximately one month may be required for in situ steam treatment ofhydrocarbons with steam and heat sources.

[1953] In some embodiments, relatively deep formations may beparticularly suitable for in situ treatment with heat sources and steaminjection. Higher steam pressures and temperatures may be readilymaintained in relatively deep formations. Furthermore, steam may be ator approaching supercritical conditions below a particular depth.Supercritical steam or near supercritical steam may facilitatepyrolyzation of hydrocarbons. In other embodiments, in situ treatment ofa relatively shallow formation may be performed with a sufficient amountof overpressure (e.g., an overpressure above a hydrostatic pressure).The amount of overpressure may depend on the strength of the formationor the overburden of the formation.

[1954] In an embodiment, in situ treatment of a formation may includeheating a selected section of the formation with one or more heatsources, and one or more cycles of steam injection. The cycles of steammay soak the formation with steam for a selected time period. Theselected time period may be about one month. In other embodiments, theselected time period may be about one month to about six months. Theselected section may be heated to a temperature between about 275° C.and about 350° C. In another embodiment, the formation may be heated toa temperature of about 350° C. to about 400° C. A vapor mixture, whichmay include pyrolyzation fluids, may be produced from the formationthrough one or more production wells placed in the formation.

[1955] In certain embodiments, in situ treatment of a formation mayinclude continuous steam injection into the formation, together withaddition of heat from heat sources. Pyrolyzation fluids may be producedfrom different portions of the formation during such treatment.

[1956]FIG. 285 illustrates a schematic of an embodiment of continuousproduction of a vapor mixture from a formation. FIG. 285 includesformation 8262 with heat transfer fluid injection well 8264 and well8266. The wells may be members of a larger pattern of wells placedthroughout the formation. A portion of a formation may be heated topyrolyzation temperatures by heating the formation with heat sources andan injected heat transfer fluid. Heat transfer fluid 8268, such assteam, may be injected through injection well 8264. Other wells may beused to provide the steam. Injected heat transfer fluid may be at atemperature between about 300° C. and about 500° C. In an embodiment,heat transfer fluid 8268 is steam.

[1957] Heat transfer fluid 8268, and heating from the heat sources, mayheat region 8263 of the formation between wells 8264 and 8266. Suchheating may heat region 8263 into a selected temperature range (e.g.,between about 275° C. and about 400° C.). An advantage of a continuousproduction method may be that the temperature across region 8263 may besubstantially uniform and substantially constant with time once theformation has reached substantial thermal equilibrium. Vapor mixture8270 may exit continuously through well 8266. Vapor mixture 8270 mayinclude pyrolysis fluids and/or steam. In one embodiment, vapor mixture8270 may be fed to surface separation unit 8272. Separation unit 8272may separate vapor mixture 8270 into stream 8274 and hydrocarbons 8276.Stream 8274 may be composed primarily of steam or water. Stream 8274 maybe re-injected into the formation. Hydrocarbons may include pyrolysisfluids and hydrocarbons distilled from the formation.

[1958] In an embodiment, production of a vapor mixture from a formationmay be performed in a batch mode. Injection of the heat transfer fluidmay continue for a period of time, together with heat from one or moreheat sources. In an embodiment, heat from the heat sources may combinewith heat from transfer fluid until the temperature of a portion of theformation is at a desired temperature (e.g., between about 275° C. andabout 400° C.). Higher or lower temperatures may also be used.Alternatively, injection may continue until a pore volume of the portionof the formation is substantially filled. After a selected period oftime subsequent to ceasing injection of the heat transfer fluid, vapormixture 8270 may be produced from the formation through wellbore 8266.The vapor mixture may include pyrolysis fluids and/or steam. In someembodiments, the vapor mixture may exit through wellbore 8264. In anembodiment, the selected period of time may be about one month.

[1959] Injected steam may contact a substantial portion of a volume ofthe formation to be treated. The heat transfer fluid may be injectedthrough one or more injection wells. Similarly, the heat sources may beplaced in one or more heater wells. The injection wells may be locatedsubstantially horizontally in the formation. Alternatively, theinjection wells may be disposed substantially vertically or any desiredangle (e.g., along dip of the formation). The heat transfer fluid may beinjected into regions of relatively high water saturation. Relativelyhigh water saturation may include water concentrations greater thanabout 50 volume percent. In some embodiments, the average spacingbetween injection wells may be between about 40 m and about 50 m. Inother embodiments, the average spacing may be between about 50 m andabout 60 m.

[1960] In an embodiment, the heat from injection of a heat transferfluid, together with heat from one or more heat sources, may pyrolyze atleast some of the hydrocarbons in the selected first section. In certainembodiments, the heat may mobilize at least some of the hydrocarbonswithin the selected first section. Injection of a heat transfer fluid,and/or heat from the heat sources, may decrease a viscosity ofhydrocarbons in the formation. Decreasing the viscosity of thehydrocarbons may allow the hydrocarbons to be more mobile. In addition,some of the heat may partially upgrade a portion of the hydrocarbons.Partial upgrading may reduce the viscosity and/or mobilize thehydrocarbons. Some of the mobilized hydrocarbons may flow (e.g., due togravity) from the selected first section of the formation to a selectedsecond section of the formation. Heat from the heat transfer fluid andthe heat sources may pyrolyze at least some of the mobilized fluids inthe selected second section.

[1961] In some embodiments, heat may be provided from one or more heatsources to at least one portion of the formation. The one or more heatsources may include electric heaters, flameless distributed combustors,or natural distributed combustors. Heat from the heat sources maytransfer to the selected first section and the selected second sectionof the formation. The heat may heat or superheat steam injected into theformation. The heat may also vaporize water in the formation to generatesteam. In addition, the heat from the heat sources may mobilize and/orpyrolyze hydrocarbons in the selected first section and/or the selectedsecond section of the formation.

[1962] In an embodiment, the selected first section and the selectedsecond section may be located in a relatively deep portion of theformation. For example, a relatively deep portion of a formation may bebetween about 100 m and about 300 m below the surface. Heat from theheat sources and the heat transfer fluid may pyrolyze at least some ofthe hydrocarbons within the selected second section of the formation. Insome embodiments, at least about 20 percent of the hydrocarbons in theformation may be pyrolyzed. The pyrolyzed hydrocarbons may have anaverage API gravity of at least about 25°.

[1963] In an embodiment, a vapor mixture may be produced from theformation. The vapor mixture may contain pyrolyzed fluids. In otherembodiments, the vapor mixture may contain pyrolyzed fluids and/or heattransfer fluid. The vapor mixture may include hydrocarbons distilledfrom the formation. The heat transfer fluid may be separated from thepyrolyzed fluids and distilled hydrocarbons at the surface of theformation. For example, heat transfer fluid may be separated using amembrane separation method. Alternatively, heat transfer fluid may beseparated from pyrolyzed fluids and distilled hydrocarbons in theformation. The pyrolyzed fluids and distilled hydrocarbons may then beproduced from the formation.

[1964] In an embodiment, the vapor mixture may be produced from theselected second section of the formation. Alternatively, the vapormixture may be produced from the selected first section.

[1965] In one embodiment, the mobilized fluids may be partially upgradedin the selected second section. The partially upgraded fluids may beproduced from the formation and re-injected back into the formation.

[1966] In certain embodiments, the vapor mixture may be produced throughone or more production wells. In some embodiments, at least some of thevapor mixture may be produced through a heat source wellbore.

[1967] In one embodiment, a liquid mixture composed primarily ofcondensed heat transfer fluid may accumulate in a portion of theformation. The liquid mixture may be produced from the formation. Theliquid mixture may include liquid hydrocarbons. The condensed heattransfer fluid may be separated from the liquid hydrocarbons in theformation and the condensed heat transfer fluid may be produced from theformation. Alternatively, the liquid mixture may be produced from theformation and fed to a separation unit. The separation unit may separatethe condensed heat transfer fluid from the liquid hydrocarbons. Theliquid hydrocarbons may then be re-injected into the formation.

[1968]FIG. 286 illustrates a cross-sectional representation of anembodiment of an in situ treatment process with steam injection. Portion8300 of the formation may be treated with steam injection. Portion 8301may be untreated. Horizontal injection and/or heat source wells 8302 maybe located in an upper or selected first section of portion 8300.Horizontal production wells 8304 may be located in a lower or selectedsecond section of portion 8300. The wells may be members of a largerpattern of wells placed throughout a portion of the formation.

[1969] Steam may be injected into the formation through wells 8302,and/or heat sources may be placed in such wells 8302 and provide heat tothe formation and/or to the steam. The heat from the steam and the heatsources may heat the selected first and second sections to pyrolyzationtemperatures and pyrolyze some of the hydrocarbons in the sections. Inaddition, heat from the steam injection and the heat sources maymobilize some hydrocarbons in the sections. The mobilized hydrocarbonsin the selected first section may flow (e.g., by gravity and or flowtowards low pressure of a pressure gradient established by productionwells) to the selected second section as indicated by arrows 8306. Someof the mobilized hydrocarbons may be pyrolyzed in the selected secondsection. Pyrolyzed fluids and/or mobilized fluids may be producedthrough production wells 8304. In an embodiment, condensed fluids (e.g.,condensed steam) may be produced through production wells in theselected second section.

[1970]FIG. 287 illustrates a cross-sectional representation of anembodiment of an in situ treatment process with steam injection and heatsources. Portion 8310 of the formation may be treated with heat fromheat sources and steam injection. Portion 8311 may be untreated. Portion8310 may include a horizontal heat source and/or injection well 8314located in an upper or selected first section. Horizontal productionwell 8312 may be located above the injection well in the selected firstsection of portion 8310. The production well and/or the injection wellmay include a heat source. Water and oil production well 8316 may beplaced in the selected second section of the formation. The wells may bemembers of a larger pattern of wells placed throughout a portion of theformation.

[1971] Heat and/or steam may be provided to the formation through well8314. Such heat and steam may heat the selected first and secondsections to pyrolyzation temperatures. Hydrocarbons may be pyrolyzed inthe selected first section between well 8312 and well 8314. In addition,the heat may mobilize some hydrocarbons in the sections. The mobilizedhydrocarbons in the selected first section may flow through region 8319to the selected second section as indicated by arrows 8318. Some of themobilized hydrocarbons may be pyrolyzed in the selected second section.Pyrolyzed fluids and/or mobilized fluids may be produced throughproduction well 8312. In addition, condensed fluids (e.g., steam) may beproduced through production well 8316 in the selected second section.

[1972] In one embodiment, a method of treating an oil shale formation insitu may include heating the formation with heat sources, and alsoinjecting a heat transfer fluid into a formation and allowing the heattransfer fluid to flow through the formation. Heat transfer fluid may beinjected into the formation through one or more injection wells. Theinjection wells may be located substantially horizontally in theformation. Alternatively, the injection wells may be disposedsubstantially vertically in the formation or at a desired angle. Thesize of a selected section of the formation may increase as a heattransfer fluid front migrates through the formation. “Heat transferfluid front” is a moving boundary between the portion of the formationtreated by heat transfer fluid and the portion untreated by heattransfer fluid. The selected section may be a portion of the formationtreated or contacted by the heat transfer fluid. Heat from the heattransfer fluid, together with heat from one or more heat sources, maypyrolyze at least some of the hydrocarbons within the selected sectionof the formation. In an embodiment, the average temperature of theselected section may be about 300° C., which corresponds to a heattransfer fluid pressure of about 90 bars.

[1973] In some embodiments, heat from the heat transfer fluid and/or oneor more heat sources may mobilize at least some of the hydrocarbons atthe heat transfer fluid front. The mobilized hydrocarbons may flowsubstantially parallel to the heat transfer fluid front. Heat from theheat transfer fluid, in conjunction with heat from the heat sources, maypyrolyze at least some of the hydrocarbons in the mobilized fluid.

[1974] In an embodiment, a vapor mixture may migrate to an upper portionof the formation. The vapor mixture may include pyrolysis fluids. Thevapor mixture may also include heat transfer fluid and/or distilledhydrocarbons. In an embodiment, the vapor mixture may be produced froman upper portion of the formation. The vapor mixture may be producedthrough one or more production wells located substantially horizontallyin the formation.

[1975] In one embodiment, a portion of the heat transfer fluid maycondense and flow to a lower portion of the selected section. A portionof the condensed heat transfer fluid may be produced from a lowerportion of the selected section. The condensed heat transfer fluid maybe produced through one or more production wells. Production wells maybe located substantially horizontally in the formation.

[1976]FIG. 288 illustrates a cross-sectional representation of anembodiment of an in situ treatment process with heat sources and steaminjection. Portion 8320 of the formation may be treated with heatsources and steam injection. Portion 8321 may be untreated. Portion 8320may include horizontal heat source and/or injection well 8326.Alternatively or in addition, portion 8320 may include vertical heatsource and/or injection well 8324. Horizontal production well 8328 maybe located in an upper portion of the formation. Portion 8320 may alsoinclude condensed fluid production well 8330 (production well 8330 maycontain one or more heat sources). The wells may be members of a largerpattern of wells placed throughout a portion of the formation.

[1977] Heat and/or steam may be provided into the formation throughwells 8326 or 8324. The heat and/or steam may flow through the formationin the direction indicated by arrows 8332. A size of a section treatedby the heat and/or steam (i.e., a selected section) increases as theheat and/or steam flows through the untreated portion of the formation.The formation may include migrating heat and/or steam front 8339 at aboundary between portion 8320 and portion 8321.

[1978] Mobilized fluids may flow in the direction of arrows 8334 towardproduction well 8328. Fluids may be pyrolyzed and produced throughproduction well 8328. Steam and distilled hydrocarbons may also beproduced through well 8328. In addition, condensed fluids may flowdownward in the direction of arrows 8336. The condensed fluids may beproduced through production well 8330. The heat source in productionwell 8330 may pyrolyze some of the produced hydrocarbons.

[1979] Heat form the heat sources and/or steam may mobilize somehydrocarbons at the migrating steam front. The mobilized hydrocarbonsmay flow downward in a direction substantially parallel to the front asindicated by arrow 8338. A portion of the mobilized hydrocarbons may bepyrolyzed. At least some of the mobilized hydrocarbons may be producedthrough production well 8328 or production well 8330.

[1980] In certain embodiments, existing steam treatmentprocesses/systems may be enhanced by the addition of one or more heatsources to the process/system. Heat sources may be placed in locationssuch that heat from the heat source openings will heat areas of theformation that are not heated (or that are less heated) by the steam.For example, if the steam is preferentially flowing in certain pathwaysthrough the formation, the heat sources may be placed in locations thatheat areas of the formations that are less heated by steam in thesepathways. In some embodiments, hydrocarbon fluids may be producedthrough a heel portion of a wellbore of a heat source. The heel portionof the heat source may be at a lower temperature than the toe portion ofthe heat source. Efficiency and production of hydrocarbons from a steamflood may be enhanced.

[1981] Some oil shale formations may contain a significant portion ofadsorbed and/or absorbed methane. The formation may be in a waterrecharge zone. Only a small portion of the methane may be produced fromoil shale formations without removing the formation water. In some casesthe inflow of water is so large that the hydrocarbon containing materialcannot be dewatered effectively. The removal of the formation water mayreduce pressure in the oil shale formation and cause the release of someadsorbed methane. The removal of formation water may reduce pressure inthe oil shale formation and cause the release of some adsorbed methane.In some embodiments, the dewatering process may result in recovery of upto about 30% of adsorbed methane from a portion of the formation. Insome embodiments, carbon dioxide may be injected into a formation tofurther enhance recovery of methane. In certain embodiments, heating anoil shale formation may cause thermal desorption of gas from a portionof the oil shale formation.

[1982] Increasing the average temperature of a formation with entrainedmethane may increase the yield of methane from the formation.Substantial recovery of entrained methane may be achieved at atemperature at or above approximately the boiling point of water in theformation. During heating, substantially all free moisture may beremoved from a portion of the formation after the portion has reached anaverage temperature of about the ambient boiling point of water.

[1983] Methane recovered from thermal desorption during heating may beused as fuel for an in situ treatment process. For example, methane maybe used for power generation to run electric heater wells. In addition,methane may be used as fuel for gas fired heater wells or combustionheaters.

[1984] All or almost all methane that is entrained in an oil shaleformation may be produced during an in situ conversion process. In anembodiment, freeze wells may be installed around a portion of aformation that includes adsorbed methane to define a treatment area.Heat sources, production wells, and/or dewatering wells may be installedin the treatment area prior to, simultaneously with, or afterinstallation of the freeze wells. The freeze wells may be activated toform a frozen barrier that inhibits water inflow into the treatmentarea. After formation of the frozen barrier, dewatering wells and/orselected production wells may be used to remove formation water from thetreatment area. Some of the methane entrained within the formation maybe released from the formation and recovered as the water is removed.Heat sources may be activated to begin heating the formation. Heat fromthe heat sources may release methane entrained in the formation. Themethane may be produced from production wells in the treatment area.Early production of adsorbed methane may significantly improve theeconomics of an in situ conversion process.

[1985] Water, in the form of saline or a solution with high levels ofdissolved solids, may be provided to a hot spent reservoir. Water to bedesalinated in a hot spent reservoir may originate from the ocean and/orfrom deep non-potable reservoirs. As water flows into the hot spentreservoir, the water may be evaporated and produced from the formationas steam. This water may be condensed into potable water having a lowtotal dissolved solids content. Condensation of the produced water mayoccur in surface facilities or in subsurface conduits. Salts and otherdissolved solids may remain in the reservoir. The salts and dissolvedsolids may be stored in the reservoir. Alternatively, effluent fromsurface facilities may be provided to a hot spent formation fordesalinization and/or disposal.

[1986] Utilizing a hot spent formation to desalinate fluids may recoversome heat from the formation. After a temperature within the formationfalls below a boiling point of a fluid, desalinization may cease.Alternatively, a section of a formation may be continually heated tomaintain conditions appropriate for desalinization. Desalinization maycontinue until a permeability and/or a porosity of a section issignificantly reduced from the precipitation of solids. In someembodiments, heat from surface facilities may be used to run a surfacedesalinization plant, with produced salts and solids being injected intoa portion of the formation, or to preheat fluids being injected into theformation to minimize temperature change within the formation.

[1987] Water generated from a desalination process may be sold to alocal market for use as potable and/or agricultural water. Thedesalinated water may provide additional resources to geographical areasthat have severe water supply limitations.

[1988] Combustion of gaseous by-products from an in situ conversionprocess as well as fluids generated in surface facilities may beutilized to generate heat and/or energy for use in the in situconversion process. For example, a low heating value stream (LHVstream), such as tail gas from the treating/recovery operations, may becatalytically combusted to generate heat and increase temperatures to arange needed for the in situ conversion process. A monolithic substrate(i.e., honeycomb such as Torvex (Du Pont) and/or Cordierite (Corning))with good flow geometry and/or minimal pressure drops may be used in thecombustor. In a conventional process, a gaseous by-product stream may beflared, since the heating value is considered too low to sustain stablethermal combustion. Utilizing energy in these streams may increase anoverall efficiency of the treatment system for formations.

[1989] In this patent, certain U.S. patents, U.S. patent applications,and other materials (e.g., articles) have been incorporated byreference. The text of such U.S. patents, U.S. patent applications, andother materials is, however, only incorporated by reference to theextent that no conflict exists between such text and the otherstatements and drawings set forth herein. In the event of such conflict,then any such conflicting text in such incorporated by reference U.S.patents, U.S. patent applications, and other materials is specificallynot incorporated by reference in this patent.

[1990] Further modifications and alternative embodiments of variousaspects of the invention may be apparent to those skilled in the art inview of this description. Accordingly, this description is to beconstrued as illustrative only and is for the purpose of teaching thoseskilled in the art the general manner of carrying out the invention. Itis to be understood that the forms of the invention shown and describedherein are to be taken as the presently preferred embodiments. Elementsand materials may be substituted for those illustrated and describedherein, parts and processes may be reversed, and certain features of theinvention may be utilized independently, all as would be apparent to oneskilled in the art after having the benefit of this description of theinvention. Changes may be made in the elements described herein withoutdeparting from the spirit and scope of the invention as described in thefollowing claims.

What is claimed is:
 1. A method of treating an oil shale formation insitu, comprising: providing heat from one or more heat sources to atleast one portion of the formation; allowing the heat to transfer fromthe one or more heat sources to a selected section of the formation;controlling the heat from the one or more heat sources such that anaverage temperature within at least a majority of the selected sectionof the formation is less than about 375° C.; and producing a mixturefrom the formation.
 2. The method of claim 1, wherein the one or moreheat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation. 3.The method of claim 1, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 4. The method of claim 1, wherein the oneor more heat sources comprise electrical heaters.
 5. The method of claim1, wherein the one or more heat sources comprise surface burners.
 6. Themethod of claim 1, wherein the one or more heat sources compriseflameless distributed combustors.
 7. The method of claim 1, wherein theone or more heat sources comprise natural distributed combustors.
 8. Themethod of claim 1, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.9. The method of claim 1, further comprising controlling a pressurewithin at least a majority of the selected section of the formation witha valve coupled to at least one of the one or more heat sources.
 10. Themethod of claim 1, further comprising controlling a pressure within atleast a majority of the selected section of the formation with a valvecoupled to a production well located in the formation.
 11. The method ofclaim 1, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 12. The method of claim 1, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity(C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 13. The method of claim 1, whereinallowing the heat to transfer from the one or more heat sources to theselected section comprises transferring heat substantially byconduction.
 14. The method of claim 1, wherein providing heat from theone or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 15. The method of claim 1,wherein the produced mixture comprises condensable hydrocarbons havingan API gravity of at least about 25°.
 16. The method of claim 1, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 17. The method of claim 1, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 18. The method of claim 1,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 19. The method of claim 1,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 20. The method ofclaim 1, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 21. Themethod of claim 1, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 22. The methodof claim 1, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 23. Themethod of claim 1, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 24. The method of claim1, wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 25. The methodof claim 1, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 26. The method of claim 1,wherein the produced mixture comprises condensable hydrocarbons, andwherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 27. The method of claim 1, wherein theproduced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, and wherein greater thanabout 10% by volume of the non-condensable component comprises hydrogenand wherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 28. The method of claim 1, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 29. The method of claim 1,wherein the produced mixture comprises ammonia, and wherein the ammoniais used to produce fertilizer.
 30. The method of claim 1, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 31. The method of claim 1, furthercomprising controlling formation conditions such that the producedmixture comprises a partial pressure of H₂ within the mixture greaterthan about 0.5 bars.
 32. The method of claim 31, wherein the partialpressure of H₂ is measured when the mixture is at a production well. 33.The method of claim 1, wherein controlling formation conditionscomprises recirculating a portion of hydrogen from the mixture into theformation.
 34. The method of claim 1, further comprising altering apressure within the formation to inhibit production of hydrocarbons fromthe formation having carbon numbers greater than about
 25. 35. Themethod of claim 1, further comprising: providing hydrogen (H₂) to theheated section to hydrogenate hydrocarbons within the section; andheating a portion of the section with heat from hydrogenation.
 36. Themethod of claim 1, wherein the produced mixture comprises hydrogen andcondensable hydrocarbons, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 37. The method of claim 1, wherein allowingthe heat to transfer comprises increasing a permeability of a majorityof the selected section to greater than about 100 millidarcy.
 38. Themethod of claim 1, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 39. The method of claim 1, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 40. The methodof claim 1, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 41. The methodof claim 40, wherein at least about 20 heat sources are disposed in theformation for each production well.
 42. The method of claim 1, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, and wherein the unitof heat sources comprises a triangular pattern.
 43. The method of claim1, further comprising providing heat from three or more heat sources toat least a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 44. The method of claim 1, furthercomprising separating the produced mixture into a gas stream and aliquid stream.
 45. The method of claim 1, further comprising separatingthe produced mixture into a gas stream and a liquid stream andseparating the liquid stream into an aqueous stream and a non-aqueousstream.
 46. The method of claim 1, wherein the produced mixturecomprises H₂S, the method further comprising separating a portion of theH₂S from non-condensable hydrocarbons.
 47. The method of claim 1,wherein the produced mixture comprises CO₂, the method furthercomprising separating a portion of the CO₂ from non-condensablehydrocarbons.
 48. The method of claim 1, wherein the mixture is producedfrom a production well, wherein the heating is controlled such that themixture can be produced from the formation as a vapor.
 49. The method ofclaim 1, wherein the mixture is produced from a production well, themethod further comprising heating a wellbore of the production well toinhibit condensation of the mixture within the wellbore.
 50. The methodof claim 1, wherein the mixture is produced from a production well,wherein a wellbore of the production well comprises a heater elementconfigured to heat the formation adjacent to the wellbore, and furthercomprising heating the formation with the heater element to produce themixture, wherein the mixture comprises a large non-condensablehydrocarbon gas component and H₂.
 51. The method of claim 1, wherein theminimum pyrolysis temperature is about 270° C.
 52. The method of claim1, further comprising maintaining the pressure within the formationabove about 2.0 bars absolute to inhibit production of fluids havingcarbon numbers above
 25. 53. The method of claim 1, further comprisingcontrolling pressure within the formation in a range from aboutatmospheric pressure to about 100 bars, as measured at a wellhead of aproduction well, to control an amount of condensable hydrocarbons withinthe produced mixture, wherein the pressure is reduced to increaseproduction of condensable hydrocarbons, and wherein the pressure isincreased to increase production of non-condensable hydrocarbons. 54.The method of claim 1, further comprising controlling pressure withinthe formation in a range from about atmospheric pressure to about 100bars, as measured at a wellhead of a production well, to control an APIgravity of condensable hydrocarbons within the produced mixture, whereinthe pressure is reduced to decrease the API gravity, and wherein thepressure is increased to reduce the API gravity.
 55. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least a portion of the formation;allowing the heat to transfer from at least the portion to a selectedsection of the formation substantially by conduction of heat; pyrolyzingat least some hydrocarbons within the selected section of the formation;and producing a mixture from the formation.
 56. The method of claim 55,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 57. The method of claim 55, wherein the one or more heatsources comprise electrical heaters.
 58. The method of claim 55, whereinthe one or more heat sources comprise surface burners.
 59. The method ofclaim 55, wherein the one or more heat sources comprise flamelessdistributed combustors.
 60. The method of claim 55, wherein the one ormore heat sources comprise natural distributed combustors.
 61. Themethod of claim 55, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.62. The method of claim 55, further comprising controlling the heat suchthat an average heating rate of the selected section is less than about1.0° C. per day during pyrolysis.
 63. The method of claim 55, whereinproviding heat from the one or more heat sources to at least the portionof formation comprises: heating a selected volume (V) of the oil shaleformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 64. The methodof claim 55, wherein providing heat from the one or more heat sourcescomprises heating the selected section such that a thermal conductivityof at least a portion of the selected section is greater than about 0.5W/(m ° C.).
 65. The method of claim 55, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 66. The method of claim 55, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins.
 67. Themethod of claim 55, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 68. The method of claim 55, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 69. The method of claim 55, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 70. The method of claim 55, whereinthe produced mixture comprises condensable hydrocarbons, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 71. The method of claim 55, whereinthe produced mixture comprises condensable hydrocarbons, wherein about5% by weight to about 30% by weight of the condensable hydrocarbonscomprise oxygen containing compounds, and wherein the oxygen containingcompounds comprise phenols.
 72. The method of claim 55, wherein theproduced mixture comprises condensable hydrocarbons, and wherein greaterthan about 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 73. The method of claim 55, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 74. The method of claim 55, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 75. The method of claim 55, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.76. The method of claim 55, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 77. Themethod of claim 55, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 78. The method of claim 55, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 79. The method of claim 55, further comprising controlling apressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 80. The method of claim 55, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 81. The method of claim 80, wherein the partialpressure of H₂ is measured when the mixture is at a production well. 82.The method of claim 55, further comprising altering a pressure withinthe formation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than about
 25. 83. The method of claim 55,wherein controlling formation conditions comprises recirculating aportion of hydrogen from the mixture into the formation.
 84. The methodof claim 55, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 85. The method ofclaim 55, wherein the produced mixture comprises hydrogen andcondensable hydrocarbons, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 86. The method of claim 55, wherein allowingthe heat to transfer comprises increasing a permeability of a majorityof the selected section to greater than about 100 millidarcy.
 87. Themethod of claim 55, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 88. The method of claim 55, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 89. The methodof claim 55, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 90. The methodof claim 89, wherein at least about 20 heat sources are disposed in theformation for each production well.
 91. The method of claim 55, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, and wherein the unitof heat sources comprises a triangular pattern.
 92. The method of claim55, further comprising providing heat from three or more heat sources toat least a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 93. A method of treating an oilshale formation in situ, comprising: providing heat from one or moreheat sources to at least a portion of the formation; allowing the heatto transfer from the one or more heat sources to a selected section ofthe formation; controlling the heat from the one or more heat sourcessuch that an average temperature within at least a majority of theselected section of the formation is less than about 370° C. such thatproduction of a substantial amount of hydrocarbons having carbon numbersgreater than 25 is inhibited; controlling a pressure within at least amajority of the selected section of the formation, wherein thecontrolled pressure is at least 2.0 bars; and producing a mixture fromthe formation, wherein about 0.1% by weight of the produced mixture toabout 15% by weight of the produced mixture are olefins, and wherein anaverage carbon number of the produced mixture is greater than 1 and lessthan about
 25. 94. The method of claim 93, wherein the one or more heatsources comprise at least two heat sources, and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 95. Themethod of claim 93, wherein controlling formation conditions comprisesmaintaining a temperature within the selected section within a pyrolysistemperature range.
 96. The method of claim 93, wherein the one or moreheat sources comprise electrical heaters.
 97. The method of claim 93,wherein the one or more heat sources comprise surface burners.
 98. Themethod of claim 93, wherein the one or more heat sources compriseflameless distributed combustors.
 99. The method of claim 93, whereinthe one or more heat sources comprise natural distributed combustors.100. The method of claim 93, further comprising controlling a pressureand a temperature within at least a majority of the selected section ofthe formation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.101. The method of claim 93, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 102. The method of claim 93,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of the oilshale formation from the one or more heat sources, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day provided to the volume is equal to orless than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 103. The methodof claim 93, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 104. The method of claim93, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 105. The method of claim 93, wherein the produced mixture comprisescondensable hydrocarbons, and wherein about 0.1% by weight to about 15%by weight of the condensable hydrocarbons are olefins.
 106. The methodof claim 93, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15. 107.The method of claim 93, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 108. The method of claim 93, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 109. The method of claim 93, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 110. The method of claim 93, whereinthe produced mixture comprises condensable hydrocarbons, wherein about5% by weight to about 30% by weight of the condensable hydrocarbonscomprise oxygen containing compounds, and wherein the oxygen containingcompounds comprise phenols.
 111. The method of claim 93, wherein theproduced mixture comprises condensable hydrocarbons, and wherein greaterthan about 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 112. The method of claim 93, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 113. The method of claim 93, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 114. The method of claim 93, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.115. The method of claim 93, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 116. Themethod of claim 93, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 117. The method of claim 93, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 118. The method of claim 93, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 119. The method of claim 118, wherein the partialpressure of H₂ is measured when the mixture is at a production well.120. The method of claim 93, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 121. The methodof claim 93, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 122. The method ofclaim 93, wherein the produced mixture comprises hydrogen andcondensable hydrocarbons, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 123. The method of claim 93, wherein allowingthe heat to transfer comprises increasing a permeability of a majorityof the selected section to greater than about 100 millidarcy.
 124. Themethod of claim 93, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 125. The method of claim 93, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 126. The methodof claim 93, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 127. The methodof claim 126, wherein at least about 20 heat sources are disposed in theformation for each production well.
 128. The method of claim 93, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, and wherein the unitof heat sources comprises a triangular pattern.
 129. The method of claim93, further comprising providing heat from three or more heat sources toat least a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 130. The method of claim 93, furthercomprising separating the produced mixture into a gas stream and aliquid stream.
 131. The method of claim 93, further comprisingseparating the produced mixture into a gas stream and a liquid streamand separating the liquid stream into an aqueous stream and anon-aqueous stream.
 132. The method of claim 93, wherein the producedmixture comprises H₂S, the method further comprising separating aportion of the H₂S from non-condensable hydrocarbons.
 133. The method ofclaim 93, wherein the produced mixture comprises CO₂, the method furthercomprising separating a portion of the CO₂ from non-condensablehydrocarbons.
 134. The method of claim 93, wherein the mixture isproduced from a production well, wherein the heating is controlled suchthat the mixture can be produced from the formation as a vapor.
 135. Themethod of claim 93, wherein the mixture is produced from a productionwell, the method further comprising heating a wellbore of the productionwell to inhibit condensation of the mixture within the wellbore. 136.The method of claim 93, wherein the mixture is produced from aproduction well, wherein a wellbore of the production well comprises aheater element configured to heat the formation adjacent to thewellbore, and further comprising heating the formation with the heaterelement to produce the mixture, wherein the produced mixture comprise alarge non-condensable hydrocarbon gas component and H₂.
 137. The methodof claim 93, wherein the minimum pyrolysis temperature is about 270° C.138. The method of claim 93, further comprising maintaining the pressurewithin the formation above about 2.0 bars absolute to inhibit productionof fluids having carbon numbers above
 25. 139. The method of claim 93,further comprising controlling pressure within the formation in a rangefrom about atmospheric pressure to about 100 bars absolute, as measuredat a wellhead of a production well, to control an amount of condensablefluids within the produced mixture, wherein the pressure is reduced toincrease production of condensable fluids, and wherein the pressure isincreased to increase production of non-condensable fluids.
 140. Themethod of claim 93, further comprising controlling pressure within theformation in a range from about atmospheric pressure to about 100 barsabsolute, as measured at a wellhead of a production well, to control anAPI gravity of condensable fluids within the produced mixture, whereinthe pressure is reduced to decrease the API gravity, and wherein thepressure is increased to reduce the API gravity.
 141. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; controlling a pressure within atleast a majority of the selected section of the formation, wherein thecontrolled pressure is at least about 2.0 bars absolute; and producing amixture from the formation.
 142. The method of claim 141, whereincontrolling the pressure comprises controlling the pressure with a valvecoupled to at least one of the one or more heat sources.
 143. The methodof claim 141, wherein controlling the pressure comprises controlling thepressure with a valve coupled to a production well located in theformation.
 144. The method of claim 141, wherein the one or more heatsources comprise at least two heat sources, and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 145. Themethod of claim 141, wherein controlling formation conditions comprisesmaintaining a temperature within the selected section within a pyrolysistemperature range.
 146. The method of claim 141, wherein the one or moreheat sources comprise electrical heaters.
 147. The method of claim 141,wherein the one or more heat sources comprise surface burners.
 148. Themethod of claim 141, wherein the one or more heat sources compriseflameless distributed combustors.
 149. The method of claim 141, whereinthe one or more heat sources comprise natural distributed combustors.150. The method of claim 141, further comprising controlling atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.151. The method of claim 141, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 152. The method of claim 141,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of the oilshale formation from the one or more heat sources, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day provided to the volume is equal to orless than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 153. The methodof claim 141, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 154. The method of claim141, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 155. The method of claim 141, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 156. The method of claim 141, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 157.The method of claim 141, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 158. The method of claim 141, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 159. The method of claim 141, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 160. The method of claim 141,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 161. The method ofclaim 141, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 162. Themethod of claim 141, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 163. The method ofclaim 141, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 164. The method of claim 141, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 165. The methodof claim 141, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 166. The method of claim141, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 167. The method of claim 141, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 168. The method of claim141, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 169. The method of claim 141,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 170. The method ofclaim 169, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 171. The method of claim 141, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 172. The method of claim 141, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 173. The method of claim 141, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 174. The method of claim 141, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 175. The method of claim 141, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 176. The methodof claim 141, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 177. The method of claim 141, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 178. The methodof claim 141, wherein producing the mixture from the formation comprisesproducing the mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well.179. The method of claim 178, wherein at least about 20 heat sources aredisposed in the formation for each production well.
 180. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; and controlling a pressure within atleast a majority of the selected section of the formation, wherein thecontrolled pressure is at least about 2.0 bars absolute; controlling theheat from the one or more heat sources such that an average temperaturewithin at least a majority of the selected section of the formation isless than about 375° C.; and producing a mixture from the formation.181. The method of claim 180, wherein the one or more heat sourcescomprise at least two heat sources, and wherein superposition of heatfrom at least the two heat sources pyrolyzes at least some hydrocarbonswithin the selected section of the formation.
 182. The method of claim180, wherein controlling formation conditions comprises maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 183. The method of claim 180, wherein the one or more heatsources comprise electrical heaters.
 184. The method of claim 180,wherein the one or more heat sources comprise surface burners.
 185. Themethod of claim 180, wherein the one or more heat sources compriseflameless distributed combustors.
 186. The method of claim 180, whereinthe one or more heat sources comprise natural distributed combustors.187. The method of claim 180, further comprising controlling a pressureand a temperature within at least a majority of the selected section ofthe formation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.188. The method of claim 180, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 189. The method of claim 180,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of the oilshale formation from the one or more heat sources, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day provided to the volume is equal to orless than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 190. The methodof claim 180, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 191. The method of claim180, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 192. The method of claim 180, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 193. The method of claim 180, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 194.The method of claim 180, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 195. Themethod of claim 180, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 196. The method of claim 180, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 197. The method of claim 180, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 198. The method of claim 180,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 199. The method ofclaim 180, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 200. Themethod of claim 180, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 201. The method ofclaim 180, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 202. The method of claim 180, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 203. The methodof claim 180, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 204. The method of claim180, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 205. The method of claim 180, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 206. The method of claim180, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 207. The method of claim 180,wherein controlling the heat further comprises controlling the heat suchthat coke production is inhibited.
 208. The method of claim 180, furthercomprising controlling formation conditions to produce a mixture ofcondensable hydrocarbons and H₂, wherein a partial pressure of H₂ withinthe mixture is greater than about 0.5 bars.
 209. The method of claim208, wherein the partial pressure of H₂ is measured when the mixture isat a production well.
 210. The method of claim 180, further comprisingaltering the pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 211. The method of claim 180, wherein controlling formationconditions comprises recirculating a portion of hydrogen from themixture into the formation.
 212. The method of claim 180, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 213. The method of claim 180, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 214. The method of claim 180, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 215. The methodof claim 180, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 216. The method of claim 180, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 217. The methodof claim 180, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 218. The methodof claim 217, wherein at least about 20 heat sources are disposed in theformation for each production well.
 219. The method of claim 180,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 220.The method of claim 180, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 221. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; producing a mixture from theformation, wherein at least a portion of the mixture is produced duringthe pyrolysis and the mixture moves through the formation in a vaporphase; and maintaining a pressure within at least a majority of theselected section above about 2.0 bars absolute.
 222. The method of claim221, wherein the one or more heat sources comprise at least two heatsources, and wherein superposition of heat from at least the two heatsources pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 223. The method of claim 221, wherein controllingformation conditions comprises maintaining a temperature within theselected section within a pyrolysis temperature range.
 224. The methodof claim 221, wherein the one or more heat sources comprise electricalheaters.
 225. The method of claim 221, wherein the one or more heatsources comprise surface burners.
 226. The method of claim 221, whereinthe one or more heat sources comprise flameless distributed combustors.227. The method of claim 221, wherein the one or more heat sourcescomprise natural distributed combustors.
 228. The method of claim 221,further comprising controlling the pressure and a temperature within atleast a majority of the selected section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 229. The method of claim 221,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 230. The method of claim 221, wherein providing heat from theone or more heat sources to at least the portion of formation comprises:heating a selected volume (V) of the oil shale formation from the one ormore heat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 231. The method of claim 221, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 232. The method of claim 221, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 233. The method of claim221, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 234. The method of claim221, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 235. The method of claim 221,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 236. The method of claim 221,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 237. The method ofclaim 221, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 238.The method of claim 221, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 239. The method of claim 221, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 240. The method of claim 221, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 241. The method of claim 221, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 242. The method of claim 221, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 243. The method of claim 221, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 244. The method of claim 221, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.245. The method of claim 221, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 246. Themethod of claim 221, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 247. The method of claim 221, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 248. The method of claim 221, wherein the pressure ismeasured at a wellhead of a production well.
 249. The method of claim221, wherein the pressure is measured at a location within a wellbore ofthe production well.
 250. The method of claim 221, wherein the pressureis maintained below about 100 bars absolute.
 251. The method of claim221, further comprising controlling formation conditions to produce amixture of condensable hydrocarbons and H₂, wherein a partial pressureof H₂ within the mixture is greater than about 0.5 bars.
 252. The methodof claim 251, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 253. The method of claim 221, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 254. The method of claim 221, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 255. The method of claim 221, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 256. The method of claim 221, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 257. The method of claim 221, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 258. The methodof claim 221, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 259. The method of claim 221, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 260. The methodof claim 221, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 261. The methodof claim 260, wherein at least about 20 heat sources are disposed in theformation for each production well.
 262. The method of claim 221,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 263.The method of claim 221, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 264. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; maintaining a pressure within atleast a majority of the selected section of the formation above 2.0 barsabsolute; and producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity higher than an API gravity of condensable hydrocarbons in amixture producible from the formation at the same temperature and atatmospheric pressure.
 265. The method of claim 264, wherein the one ormore heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.266. The method of claim 264, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 267. The method of claim 264, wherein theone or more heat sources comprise electrical heaters.
 268. The method ofclaim 264, wherein the one or more heat sources comprise surfaceburners.
 269. The method of claim 264, wherein the one or more heatsources comprise flameless distributed combustors.
 270. The method ofclaim 264, wherein the one or more heat sources comprise naturaldistributed combustors.
 271. The method of claim 264, further comprisingcontrolling the pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 272. The method of claim 264,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 273. The method of claim 264, wherein providing heat from theone or more heat sources to at least the portion of formation comprises:heating a selected volume (V) of the oil shale formation from the one ormore heat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 274. The method of claim 264, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 275. The method of claim 264, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 276. The method of claim264, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 277. The method of claim264, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 278. The method of claim 264,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 279. The method of claim 264,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 280. The method ofclaim 264, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 281.The method of claim 264, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 282. The method of claim 264, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 283. The method of claim 264, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 284. The method of claim 264, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 285. The method of claim 264, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 286. The method of claim 264, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 287. The method of claim 264, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.288. The method of claim 264, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 289. Themethod of claim 264, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 290. The method of claim 264, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 291. The method of claim 264, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 292. The method of claim 264, wherein a partialpressure of H₂ is measured when the mixture is at a production well.293. The method of claim 264, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 294. The methodof claim 264, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.295. The method of claim 264, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 296. The method of claim 264, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 297. Themethod of claim 264, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 298. The method of claim 264, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 299.The method of claim 264, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 300. The method of claim 264, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 301. The method of claim 300,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 302. The method of claim 264, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 303. The method of claim 264,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 304. A method of treating an oilshale formation in situ, comprising: providing heat from one or moreheat sources to at least a portion of the formation; allowing the heatto transfer from the one or more heat sources to a selected section ofthe formation; maintaining a pressure within at least a majority of theselected section of the formation to above 2.0 bars absolute; andproducing a fluid from the formation, wherein condensable hydrocarbonswithin the fluid comprise an atomic hydrogen to atomic carbon ratio ofgreater than about 1.75.
 305. The method of claim 304, wherein the oneor more heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.306. The method of claim 304, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 307. The method of claim 304, wherein theone or more heat sources comprise electrical heaters.
 308. The method ofclaim 304, wherein the one or more heat sources comprise surfaceburners.
 309. The method of claim 304, wherein the one or more heatsources comprise flameless distributed combustors.
 310. The method ofclaim 304, wherein the one or more heat sources comprise naturaldistributed combustors.
 311. The method of claim 304, further comprisingcontrolling the pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 312. The method of claim 304,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 313. The method of claim 304, wherein providing heat from theone or more heat sources to at least the portion of formation comprises:heating a selected volume (V) of the oil shale formation from the one ormore heat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 314. The method of claim 304, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 315. The method of claim 304, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 316. The method of claim304, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 317. The method of claim304, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 318. The method of claim 304,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 319. The method of claim 304,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 320. The method ofclaim 304, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 321.The method of claim 304, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 322. The method of claim 304, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 323. The method of claim 304, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 324. The method of claim 304, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 325. The method of claim 304, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 326. The method of claim 304, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 327. The method of claim 304, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.328. The method of claim 304, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 329. Themethod of claim 304, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 330. The method of claim 304, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 331. The method of claim 304, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 332. The method of claim 304, wherein a partialpressure of H₂ is measured when the mixture is at a production well.333. The method of claim 304, further comprising altering the pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 334. The methodof claim 304, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.335. The method of claim 304, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 336. The method of claim 304, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 337. Themethod of claim 304, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 338. The method of claim 304, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 339.The method of claim 304, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 340. The method of claim 304, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 341. The method of claim 340,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 342. The method of claim 304, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 343. The method of claim 304,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 344. A method of treating an oilshale formation in situ, comprising: providing heat from one or moreheat sources to at least a portion of the formation; allowing the heatto transfer from the one or more heat sources to a selected section ofthe formation; maintaining a pressure within at least a majority of theselected section of the formation to above 2.0 bars absolute; andproducing a mixture from the formation, wherein the produced mixturecomprises a higher amount of non-condensable components as compared tonon-condensable components producible from the formation under the sametemperature conditions and at atmospheric pressure.
 345. The method ofclaim 344, wherein the one or more heat sources comprise at least twoheat sources, and wherein superposition of heat from at least the twoheat sources pyrolyzes at least some hydrocarbons within the selectedsection of the formation.
 346. The method of claim 344, whereincontrolling formation conditions comprises maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 347.The method of claim 344, wherein the one or more heat sources compriseelectrical heaters.
 348. The method of claim 344, wherein the one ormore heat sources comprise surface burners.
 349. The method of claim344, wherein the one or more heat sources comprise flameless distributedcombustors.
 350. The method of claim 344, wherein the one or more heatsources comprise natural distributed combustors.
 351. The method ofclaim 344, further comprising controlling the pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 352. The method ofclaim 344, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 353. The method of claim 344, wherein providing heatfrom the one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 354. The method of claim 344, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 355. The method of claim 344, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 356. The method of claim344, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 357. The method of claim344, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 358. The method of claim 344,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 359. The method of claim 344,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 360. The method ofclaim 344, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 361.The method of claim 344, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 362. The method of claim 344, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 363. The method of claim 344, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 364. The method of claim 344, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 365. The method of claim 344, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 366. The method of claim 344, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 367. The method of claim 344, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.368. The method of claim 344, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 369. Themethod of claim 344, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 370. The method of claim 344, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 371. The method of claim 344, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 372. The method of claim 344, wherein a partialpressure of H₂ is measured when the mixture is at a production well.373. The method of claim 344, further comprising altering the pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 374. The methodof claim 344, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 375. The method ofclaim 344, wherein the produced mixture comprises hydrogen andcondensable hydrocarbons, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 376. The method of claim 344, wherein allowingthe heat to transfer comprises increasing a permeability of a majorityof the selected section to greater than about 100 millidarcy.
 377. Themethod of claim 344, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 378. The method of claim 344, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 379. The methodof claim 344, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 380. The methodof claim 379, wherein at least about 20 heat sources are disposed in theformation for each production well.
 381. The method of claim 344,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 382.The method of claim 344, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 383. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation such that superimposed heat from theone or more heat sources pyrolyzes at least about 20% by weight ofhydrocarbons within the selected section of the formation; and producinga mixture from the formation.
 384. The method of claim 383, wherein theone or more heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.385. The method of claim 383, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 386. The method of claim 383, wherein theone or more heat sources comprise electrical heaters.
 387. The method ofclaim 383, wherein the one or more heat sources comprise surfaceburners.
 388. The method of claim 383, wherein the one or more heatsources comprise flameless distributed combustors.
 389. The method ofclaim 383, wherein the one or more heat sources comprise naturaldistributed combustors.
 390. The method of claim 383, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 391. The method of claim 383,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 392. The method of claim 383, wherein providing heat from theone or more heat sources to at least the portion of formation comprises:heating a selected volume (V) of the oil shale formation from the one ormore heat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 393. The method of claim 383, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 394. The method of claim 383, wherein providing heat fromthe one or more heat sources comprises heating the selected formationsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 395. The method of claim383, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 396. The method of claim383, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 397. The method of claim 383,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 398. The method of claim 383,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 399. The method ofclaim 383, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 400.The method of claim 383, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 401. The method of claim 383, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 402. The method of claim 383, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 403. The method of claim 383, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 404. The method of claim 383, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 405. The method of claim 383, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 406. The method of claim 383, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.407. The method of claim 383, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 408. Themethod of claim 383, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 409. The method of claim 383, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 410. The method of claim 383, further comprising controllinga pressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 411. The method of claim 383, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 412. The method of claim 383, wherein a partialpressure of H₂ is measured when the mixture is at a production well.413. The method of claim 383, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 414. The methodof claim 383, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.415. The method of claim 383, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 416. The method of claim 383, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 417. Themethod of claim 383, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 418. The method of claim 383, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 419.The method of claim 383, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 420. The method of claim 383, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 421. The method of claim 420,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 422. The method of claim 383, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 423. The method of claim 383,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 424. A method of treating an oilshale formation in situ, comprising: providing heat from one or moreheat sources to at least a portion of the formation; allowing the heatto transfer from the one or more heat sources to a selected section ofthe formation such that superimposed heat from the one or more heatsources pyrolyzes at least about 20% of hydrocarbons within the selectedsection of the formation; and producing a mixture from the formation,wherein the mixture comprises a condensable component having an APIgravity of at least about 25°.
 425. The method of claim 424, wherein theone or more heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.426. The method of claim 424, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 427. The method of claim 424, wherein theone or more heat sources comprise electrical heaters.
 428. The method ofclaim 424, wherein the one or more heat sources comprise surfaceburners.
 429. The method of claim 424, wherein the one or more heatsources comprise flameless distributed combustors.
 430. The method ofclaim 424, wherein the one or more heat sources comprise naturaldistributed combustors.
 431. The method of claim 424, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 432. The method of claim 424,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 433. The method of claim 424, wherein providing heat from theone or more heat sources to at least the portion of formation comprises:heating a selected volume (V) of the oil shale formation from the one ormore heat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 434. The method of claim 424, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 435. The method of claim 424, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 436. The method of claim424, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 437. The method of claim 424,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 438. The method of claim 424,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 439. The method ofclaim 424, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 440.The method of claim 424, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 441. The method of claim 424, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 442. The method of claim 424, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 443. The method of claim 424, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 444. The method of claim 424, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 445. The method of claim 424, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 446. The method of claim 424, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.447. The method of claim 424, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 448. Themethod of claim 424, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 449. The method of claim 424, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 450. The method of claim 424, further comprising controllinga pressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 451. The method of claim 424, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 452. The method of claim 424, wherein a partialpressure of H₂ is measured when the mixture is at a production well.453. The method of claim 424, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 454. The methodof claim 424, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.455. The method of claim 424, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 456. The method of claim 424, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 457. Themethod of claim 424, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 458. The method of claim 424, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 459.The method of claim 424, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 460. The method of claim 424, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 461. The method of claim 460,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 462. The method of claim 424, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 463. The method of claim 424,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 464. A method of treating a layer ofan oil shale formation in situ, comprising: providing heat from one ormore heat sources to at least a portion of the layer, wherein the one ormore heat sources are positioned proximate an edge of the layer;allowing the heat to transfer from the one or more heat sources to aselected section of the layer such that superimposed heat from the oneor more heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation; and producing a mixture from theformation.
 465. The method of claim 464, wherein the one or more heatsources are laterally spaced from a center of the layer.
 466. The methodof claim 464, wherein the one or more heat sources are positioned in astaggered line.
 467. The method of claim 464, wherein the one or moreheat sources positioned proximate the edge of the layer can increase anamount of hydrocarbons produced per unit of energy input to the one ormore heat sources.
 468. The method of claim 464, wherein the one or moreheat sources positioned proximate the edge of the layer can increase thevolume of formation undergoing pyrolysis per unit of energy input to theone or more heat sources.
 469. The method of claim 464, wherein the oneor more heat sources comprise electrical heaters.
 470. The method ofclaim 464, wherein the one or more heat sources comprise surfaceburners.
 471. The method of claim 464, wherein the one or more heatsources comprise flameless distributed combustors.
 472. The method ofclaim 464, wherein the one or more heat sources comprise naturaldistributed combustors.
 473. The method of claim 464, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 474. The method of claim 464,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1.0° C. per day duringpyrolysis.
 475. The method of claim 464, wherein providing heat from theone or more heat sources to at least the portion of the layer comprises:heating a selected volume (V) of the oil shale formation from the one ormore heat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 476. The method of claim 464, wherein providingheat from the one or more heat sources comprises heating the selectedsection such that a thermal conductivity of at least a portion of theselected section is greater than about 0.5 W/(m ° C.).
 477. The methodof claim 464, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 478. Themethod of claim 464, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 479. The method of claim 464,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 480. The method ofclaim 464, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 481.The method of claim 464, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 482. The method of claim 464, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 483. The method of claim 464, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 484. The method of claim 464, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 485. The method of claim 464, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 486. The method of claim 464, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 487. The method of claim 464, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.488. The method of claim 464, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 489. Themethod of claim 464, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 490. The method of claim 464, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 491. The method of claim 464, further comprising controllinga pressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 492. The method of claim 464, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 493. The method of claim 492, wherein the partialpressure of H₂ is measured when the mixture is at a production well.494. The method of claim 464, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 495. The methodof claim 464, further comprising controlling formation conditions,wherein controlling formation conditions comprises recirculating aportion of hydrogen from the mixture into the formation.
 496. The methodof claim 464, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 497. The method ofclaim 464, wherein the produced mixture comprises hydrogen andcondensable hydrocarbons, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 498. The method of claim 464, wherein allowingthe heat to transfer comprises increasing a permeability of a majorityof the selected section to greater than about 100 millidarcy.
 499. Themethod of claim 464, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 500. The method of claim 464, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 501. The methodof claim 464, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 502. The methodof claim 501, wherein at least about 20 heat sources are disposed in theformation for each production well.
 503. The method of claim 464,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 504.The method of claim 464, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 505. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; and controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure;and producing a mixture from the formation.
 506. The method of claim505, wherein the one or more heat sources comprise at least two heatsources, and wherein superposition of heat from at least the two heatsources pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 507. The method of claim 505, wherein controllingformation conditions comprises maintaining a temperature within theselected section within a pyrolysis temperature range.
 508. The methodof claim 505, wherein the one or more heat sources comprise electricalheaters.
 509. The method of claim 505, wherein the one or more heatsources comprise surface burners.
 510. The method of claim 505, whereinthe one or more heat sources comprise flameless distributed combustors.511. The method of claim 505, wherein the one or more heat sourcescomprise natural distributed combustors.
 512. The method of claim 505,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 513. The method of claim 505, wherein providing heat from theone or more heat sources to at least the portion of formation comprises:heating a selected volume (V) of the oil shale formation from the one ormore heat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 514. The method of claim 505, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 515. The method of claim 505, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 516. The method of claim505, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 517. The method of claim505, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 518. The method of claim 505,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 519. The method of claim 505,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 520. The method ofclaim 505, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 521.The method of claim 505, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 522. The method of claim 505, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 523. The method of claim 505, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 524. The method of claim 505, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 525. The method of claim 505, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 526. The method of claim 505, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 527. The method of claim 505, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.528. The method of claim 505, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 529. Themethod of claim 505, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 530. The method of claim 505, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 531. The method of claim 505, wherein the controlledpressure is at least about 2.0 bars absolute.
 532. The method of claim505, further comprising controlling formation conditions to produce amixture of condensable hydrocarbons and H₂, wherein a partial pressureof H₂ within the mixture is greater than about 0.5 bars.
 533. The methodof claim 505, wherein a partial pressure of H₂ is measured when themixture is at a production well.
 534. The method of claim 505, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 535. The method of claim 505, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 536. The method of claim 505, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 537. The method of claim 505, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 538. The method of claim 505, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 539. The methodof claim 505, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 540. The method of claim 505, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 541. The methodof claim 505, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 542. The methodof claim 541, wherein at least about 20 heat sources are disposed in theformation for each production well.
 543. The method of claim 505,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 544.The method of claim 505, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 545. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation to raise an average temperature withinthe selected section to, or above, a temperature that will pyrolyzehydrocarbons within the selected section; producing a mixture from theformation; and controlling API gravity of the produced mixture to begreater than about 25 degrees API by controlling average pressure andaverage temperature in the selected section such that the averagepressure in the selected section is greater than the pressure (p) setforth in the following equation for an assessed average temperature (T)in the selected section: p=e ^([−44000/T+67]) where p is measured inpsia and T is measured in ° Kelvin.
 546. The method of claim 545,wherein the API gravity of the produced mixture is controlled to begreater than about 30 degrees API, and wherein the equation is: p=e^([−31000/T+51]).
 547. The method of claim 545, wherein the API gravityof the produced mixture is controlled to be greater than about 35degrees API, and wherein the equation is: p=e ^([−22000/T+38]).
 548. Themethod of claim 545, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 549. The method of claim 545, whereincontrolling the average temperature comprises maintaining a temperaturein the selected section within a pyrolysis temperature range.
 550. Themethod of claim 545, wherein the one or more heat sources compriseelectrical heaters.
 551. The method of claim 545, wherein the one ormore heat sources comprise surface burners.
 552. The method of claim545, wherein the one or more heat sources comprise flameless distributedcombustors.
 553. The method of claim 545, wherein the one or more heatsources comprise natural distributed combustors.
 554. The method ofclaim 545, further comprising controlling a temperature within at leasta majority of the selected section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 555. The method of claim 545,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 556. The method of claim 545, wherein providing heat from theone or more heat sources to at least the portion of formation comprises:heating a selected volume (V) of the oil shale formation from the one ormore heat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 557. The method of claim 545, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 558. The method of claim 545, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 559. The method of claim545, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 560. The method of claim 545,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 561. The method of claim 545,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 562. The method ofclaim 545, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 563.The method of claim 545, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 564. The method of claim 545, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 565. The method of claim 545, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 566. The method of claim 545, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 567. The method of claim 545, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 568. The method of claim 545, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 569. The method of claim 545, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.570. The method of claim 545, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 571. Themethod of claim 545, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 572. The method of claim 545, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 573. The method of claim 545, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 574. The method of claim 545, wherein a partialpressure of H₂ is measured when the mixture is at a production well.575. The method of claim 545, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 576. The methodof claim 545, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.577. The method of claim 545, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 578. The method of claim 545, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 579. Themethod of claim 545, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 580. The method of claim 545, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 581.The method of claim 545, wherein the heat is controlled to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured byFischer Assay.
 582. The method of claim 545, wherein producing themixture comprises producing the mixture in a production well, andwherein at least about 7 heat sources are disposed in the formation foreach production well.
 583. The method of claim 582, wherein at leastabout 20 heat sources are disposed in the formation for each productionwell.
 584. The method of claim 545, further comprising providing heatfrom three or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 585. The method of claim 545, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 586. A method of treating an oil shaleformation in situ, comprising: providing heat to at least a portion ofan oil shale formation such that a temperature (T) in a substantial partof the heated portion exceeds 270° C. and hydrocarbons are pyrolyzedwithin the heated portion of the formation; controlling a pressure (p)within at least a substantial part of the heated portion of theformation; wherein p _(bar) >e ^([(−A/T)+B−2.6744]); wherein p is thepressure in bars absolute and T is the temperature in degrees K, and Aand B are parameters that are larger than 10 and are selected inrelation to the characteristics and composition of the oil shaleformation and on the required olefin content and carbon number of thepyrolyzed hydrocarbon fluids; and producing pyrolyzed hydrocarbon fluidsfrom the heated portion of the formation.
 587. The method of claim 586,wherein A is greater than 14000 and B is greater than about 25 and amajority of the produced pyrolyzed hydrocarbon fluids have an averagecarbon number lower than 25 and comprise less than about 10% by weightof olefins.
 588. The method of claim 586, wherein T is less than about390° C., p is greater than about 1.4 bars, A is greater than about44000, and b is greater than about 67, and a majority of the producedpyrolyzed hydrocarbon fluids have an average carbon number less than 25and comprise less than 10% by weight of olefins.
 589. The method ofclaim 586, wherein T is less than about 390° C., p is greater than about2 bars, A is less than about 57000, and b is less than about 83, and amajority of the produced pyrolyzed hydrocarbon fluids have an averagecarbon number lower than about
 21. 590. The method of claim 586, furthercomprising controlling the heat such that an average heating rate of theheated portion is less than about 3° C. per day during pyrolysis. 591.The method of claim 586, wherein providing heat from the one or moreheat sources to at least the portion of formation comprises: heating aselected volume (V) of the oil shale formation from the one or more heatsources, wherein the formation has an average heat capacity (C_(v)), andwherein the heating pyrolyzes at least some hydrocarbons within theselected volume of the formation; and wherein heating energy/dayprovided to the volume is equal to or less than Pwr, wherein Pwr iscalculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is theheating energy/day, h is an average heating rate of the formation, ρ_(B)is formation bulk density, and wherein the heating rate is less thanabout 10° C./day.
 592. The method of claim 586, wherein heat istransferred substantially by conduction from the one or more heatsources to the heated portion of the formation.
 593. The method of claim586, wherein heat is transferred substantially by conduction from theone or more heat sources to the heated portion of the formation suchthat the thermal conductivity of at least part of the heated portion issubstantially uniformly modified to a value greater than about 0.6 W/m °C. and the permeability of said part increases substantially uniformlyto a value greater than 1 Darcy.
 594. The method of claim 586, furthercomprising controlling formation conditions to produce a mixture ofhydrocarbon fluids and H₂, wherein a partial pressure of H₂ within themixture flowing through the formation is greater than 0.5 bars.
 595. Themethod of claim 594, further comprising, hydrogenating a portion of theproduced pyrolyzed hydrocarbon fluids with at least a portion of theproduced hydrogen and heating the fluids with heat from hydrogenation.596. The method of claim 586, wherein the substantially gaseouspyrolyzed hydrocarbon fluids are produced from a production well, themethod further comprising heating a wellbore of the production well toinhibit condensation of the hydrocarbon fluids within the wellbore. 597.A method of treating an oil shale formation in situ, comprising:providing heat from one or more heat sources to at least a portion ofthe formation; allowing the heat to transfer from the one or more heatsources to a selected section of the formation to raise an averagetemperature within the selected section to, or above, a temperature thatwill pyrolyze hydrocarbons within the selected section; producing amixture from the formation; and controlling a weight percentage ofolefins of the produced mixture to be less than about 20% by weight bycontrolling average pressure and average temperature in the selectedsection such that the average pressure in the selected section isgreater than the pressure (p) set forth in the following equation for anassessed average temperature (T) in the selected section: p=e^([−57000/T+83]) where p is measured in psia and T is measured in °Kelvin.
 598. The method of claim 597, wherein the weight percentage ofolefins of the produced mixture is controlled to be less than about 10%by weight, and wherein the equation is: p=e ^([−16000/T+28]).
 599. Themethod of claim 597, wherein the weight percentage of olefins of theproduced mixture is controlled to be less than about 5% by weight, andwherein the equation is: p=e ^([−12000/T+22]).
 600. The method of claim597, wherein the one or more heat sources comprise at least two heatsources, and wherein superposition of heat from at least the two heatsources pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 601. The method of claim 597, wherein the one or moreheat sources comprise electrical heaters.
 602. The method of claim 597,wherein the one or more heat sources comprise surface burners.
 603. Themethod of claim 597, wherein the one or more heat sources compriseflameless distributed combustors.
 604. The method of claim 597, whereinthe one or more heat sources comprise natural distributed combustors.605. The method of claim 597, further comprising controlling atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.606. The method of claim 605, wherein controlling an average temperaturecomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 607. The method of claim 597, furthercomprising controlling the heat such that an average heating rate of theselected section is less than about 3.0° C. per day during pyrolysis.608. The method of claim 597, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 609. The method of claim 597,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of the oilshale formation from the one or more heat sources, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day provided to the volume is equal to orless than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 610. The methodof claim 597, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 611. The method of claim597, wherein providing heat from the one or more heat sources comprisesheating the selected formation such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 612. The method of claim 597, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 613. The method of claim 597, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 614.The method of claim 597, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 615. Themethod of claim 597, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 616. The method of claim 597, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 617. The method of claim 597, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 618. The method of claim 597,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 619. The method ofclaim 597, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 620. Themethod of claim 597, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 621. The method ofclaim 597, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 622. The method of claim 597, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 623. The methodof claim 597, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 624. The method of claim597, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 625. The method of claim 597, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 626. The method of claim597, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 627. The method of claim 597,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 628. The method ofclaim 597, wherein a partial pressure of H₂ is measured when the mixtureis at a production well.
 629. The method of claim 597, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 630. The method of claim 597, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 631. The method of claim 597, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 632. The method of claim 597, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 633. The method of claim 597, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 634. The methodof claim 597, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 635. The method of claim 597, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 636. The methodof claim 597, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 637. The methodof claim 636, wherein at least about 20 heat sources are disposed in theformation for each production well.
 638. The method of claim 597,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 639.The method of claim 597, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 640. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation to raise an average temperature withinthe selected section to, or above, a temperature that will pyrolyzehydrocarbons within the selected section; producing a mixture from theformation; and controlling hydrocarbons having carbon numbers greaterthan 25 of the produced mixture to be less than about 25% by weight bycontrolling average pressure and average temperature in the selectedsection such that the average pressure in the selected section isgreater than the pressure (p) set forth in the following equation for anassessed average temperature (T) in the selected section: p=e^([−14000/T+25]) where p is measured in psia and T is measured in °Kelvin.
 641. The method of claim 640, wherein the hydrocarbons havingcarbon numbers greater than 25 of the produced mixture is controlled tobe less than about 20% by weight, and wherein the equation is: p=e^([−16000/T+28]).
 642. The method of claim 640, wherein the hydrocarbonshaving carbon numbers greater than 25 of the produced mixture iscontrolled to be less than about 15% by weight, and wherein the equationis: p=e ^([−18000/T+32]).
 643. The method of claim 640, wherein the oneor more heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.644. The method of claim 640, wherein the one or more heat sourcescomprise electrical heaters.
 645. The method of claim 640, wherein theone or more heat sources comprise surface burners.
 646. The method ofclaim 640, wherein the one or more heat sources comprise flamelessdistributed combustors.
 647. The method of claim 640, wherein the one ormore heat sources comprise natural distributed combustors.
 648. Themethod of claim 640, further comprising controlling a temperature withinat least a majority of the selected section of the formation, whereinthe pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 649. The method ofclaim 648, wherein controlling the temperature comprises maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 650. The method of claim 640, further comprising controlling theheat such that an average heating rate of the selected section is lessthan about 1° C. per day during pyrolysis.
 651. The method of claim 640,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of the oilshale formation from the one or more heat sources, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day provided to the volume is equal to orless than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 652. The methodof claim 640, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 653. The method of claim640, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 654. The method of claim 640, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 655. The method of claim 640, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 656.The method of claim 640, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 657. The method of claim 640, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 658. The method of claim 640, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 659. The method of claim 640,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 660. The method ofclaim 640, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 661. Themethod of claim 640, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 662. The method ofclaim 640, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 663. The method of claim 640, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 664. The methodof claim 640, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 665. The method of claim640, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 666. The method of claim 640, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 667. The method of claim640, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 668. The method of claim 640,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 669. The method ofclaim 640, wherein a partial pressure of H₂ is measured when the mixtureis at a production well.
 670. The method of claim 640, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 671. The method of claim 640, further comprising:providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 672. The method of claim 640, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 673. The method of claim 640, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 674. The methodof claim 640, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 675. The method of claim 640, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 676. The methodof claim 640, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 677. The methodof claim 676, wherein at least about 20 heat sources are disposed in theformation for each production well.
 678. The method of claim 640,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 679.The method of claim 640, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 680. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation to raise an average temperature withinthe selected section to, or above, a temperature that will pyrolyzehydrocarbons within the selected section; producing a mixture from theformation; and controlling an atomic hydrogen to carbon ratio of theproduced mixture to be greater than about 1.7 by controlling averagepressure and average temperature in the selected section such that theaverage pressure in the selected section is greater than the pressure(p) set forth in the following equation for an assessed averagetemperature (T) in the selected section: p=e ^([−38000/T+61]) where p ismeasured in psia and T is measured in ° Kelvin.
 681. The method of claim680, wherein the atomic hydrogen to carbon ratio of the produced mixtureis controlled to be greater than about 1.8, and wherein the equation is:p=e ^([−13000/T+24]).
 682. The method of claim 680, wherein the atomichydrogen to carbon ratio of the produced mixture is controlled to begreater than about 1.9, and wherein the equation is: p=e^([−8000/T+18]).
 683. The method of claim 680, wherein the one or moreheat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.684. The method of claim 680, wherein the one or more heat sourcescomprise electrical heaters.
 685. The method of claim 680, wherein theone or more heat sources comprise surface burners.
 686. The method ofclaim 680, wherein the one or more heat sources comprise flamelessdistributed combustors.
 687. The method of claim 680, wherein the one ormore heat sources comprise natural distributed combustors.
 688. Themethod of claim 680, further comprising controlling a temperature withinat least a majority of the selected section of the formation, whereinthe pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 689. The method ofclaim 688, wherein controlling the temperature comprises maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 690. The method of claim 680, further comprising controlling theheat such that an average heating rate of the selected section is lessthan about 1° C. per day during pyrolysis.
 691. The method of claim 680,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of the oilshale formation from the one or more heat sources, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day provided to the volume is equal to orless than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 692. The methodof claim 680, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 693. The method of claim680, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 694. The method of claim 680, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 695. The method of claim 680, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 696.The method of claim 680, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 697. Themethod of claim 680, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 698. The method of claim 680, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 699. The method of claim 680, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 700. The method of claim 680,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 701. The method ofclaim 680, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 702. Themethod of claim 680, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 703. The method ofclaim 680, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 704. The method of claim 680, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 705. The methodof claim 680, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 706. The method of claim680, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 707. The method of claim 680, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 708. The method of claim680, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 709. The method of claim 680,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 710. The method ofclaim 680, wherein a partial pressure of H₂ is measured when the mixtureis at a production well.
 711. The method of claim 680, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 712. The method of claim 680, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 713. The method of claim 680, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 714. The method of claim 680, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 715. The method of claim 680, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 716. The methodof claim 680, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 717. The method of claim 680, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 718. The methodof claim 680, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 719. The methodof claim 718, wherein at least about 20 heat sources are disposed in theformation for each production well.
 720. The method of claim 680,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 721.The method of claim 680, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 722. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least one portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; controlling a pressure-temperaturerelationship within at least the selected section of the formation byselected energy input into the one or more heat sources and by pressurerelease from the selected section through wellbores of the one or moreheat sources; and producing a mixture from the formation.
 723. Themethod of claim 722, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 724. The method of claim 722, whereinthe one or more heat sources comprise at least two heat sources. 725.The method of claim 722, wherein the one or more heat sources comprisesurface burners.
 726. The method of claim 722, wherein the one or moreheat sources comprise flameless distributed combustors.
 727. The methodof claim 722, wherein the one or more heat sources comprise naturaldistributed combustors.
 728. The method of claim 722, further comprisingcontrolling the pressure-temperature relationship by controlling a rateof removal of fluid from the formation.
 729. The method of claim 722,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 730. The method of claim 722, wherein providing heat from theone or more heat sources to at least the portion of formation comprises:heating a selected volume (V) of the oil shale formation from the one ormore heat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 731. The method of claim 722, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 732. The method of claim 722, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 733. The method of claim722, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 734. The method of claim722, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 735. The method of claim 722,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 736. The method of claim 722,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 737. The method ofclaim 722, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 738.The method of claim 722, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 739. The method of claim 722, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 740. The method of claim 722, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 741. The method of claim 722, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 742. The method of claim 722, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 743. The method of claim 722, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 744. The method of claim 722, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.745. The method of claim 722, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 746. Themethod of claim 722, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 747. The method of claim 722, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 748. The method of claim 722, further comprising controllinga pressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 749. The method of claim 722, further comprising controllingformation conditions to produce a mixture of hydrocarbon fluids and H₂,wherein a partial pressure of H₂ within the mixture is greater thanabout 0.5 bars.
 750. The method of claim 722, further comprisingcontrolling formation conditions to produce a mixture of condensablehydrocarbons and H₂, wherein a partial pressure of H₂ within the mixtureis greater than about 0.5 bars.
 751. The method of claim 722, wherein apartial pressure of H₂ is measured when the mixture is at a productionwell.
 752. The method of claim 722, further comprising altering apressure within the formation to inhibit production of hydrocarbons fromthe formation having carbon numbers greater than about
 25. 753. Themethod of claim 722, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.754. The method of claim 722, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 755. The method of claim 722, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 756. Themethod of claim 722, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 757. The method of claim 722, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 758.The method of claim 722, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 759. The method of claim 722, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 760. The method of claim 759,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 761. The method of claim 722, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 762. The method of claim 722,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 763. A method of treating an oilshale formation in situ, comprising: heating a selected volume (V) ofthe oil shale formation, wherein formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 764. The method of claim 763, wherein heating aselected volume comprises heating with an electrical heater.
 765. Themethod of claim 763, wherein heating a selected volume comprises heatingwith a surface burner.
 766. The method of claim 763, wherein heating aselected volume comprises heating with a flameless distributedcombustor.
 767. The method of claim 763, wherein heating a selectedvolume comprises heating with at least one natural distributedcombustor.
 768. The method of claim 763, further comprising controllinga pressure and a temperature within at least a majority of the selectedvolume of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 769. The method of claim 763, further comprisingcontrolling the heating such that an average heating rate of theselected volume is less than about 1° C. per day during pyrolysis. 770.The method of claim 763, wherein a value for C_(v) is determined as anaverage heat capacity of two or more samples taken from the oil shaleformation.
 771. The method of claim 763, wherein heating the selectedvolume comprises transferring heat substantially by conduction.
 772. Themethod of claim 763, wherein heating the selected volume comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 773. The method of claim 763, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 774. The method of claim 763, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 775.The method of claim 763, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 776. Themethod of claim 763, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 777. The method of claim 763, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 778. The method of claim 763, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 779. The method of claim 763,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 780. The method ofclaim 763, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 781. Themethod of claim 763, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 782. The method ofclaim 763, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 783. The method of claim 763, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 784. The methodof claim 763, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 785. The method of claim763, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 786. The method of claim 763, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 787. The method of claim763, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer
 788. The method of claim 763,further comprising controlling a pressure within at least a majority ofthe selected volume of the formation, wherein the controlled pressure isat least about 2.0 bars absolute.
 789. The method of claim 763, furthercomprising controlling formation conditions to produce a mixture fromthe formation comprising condensable hydrocarbons and H₂, wherein apartial pressure of H₂ within the mixture is greater than about 0.5bars.
 790. The method of claim 763, wherein a partial pressure of H₂ ismeasured when the mixture is at a production well.
 791. The method ofclaim 763, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 792. The method of claim 763, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 793. The method of claim763, further comprising: providing hydrogen (H₂) to the heated volume tohydrogenate hydrocarbons within the volume; and heating a portion of thevolume with heat from hydrogenation.
 794. The method of claim 763,wherein the produced mixture comprises hydrogen and condensablehydrocarbons, the method further comprising hydrogenating a portion ofthe produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 795. The method of claim 763, further comprisingincreasing a permeability of a majority of the selected volume togreater than about 100 millidarcy.
 796. The method of claim 763, furthercomprising substantially uniformly increasing a permeability of amajority of the selected volume.
 797. The method of claim 763, furthercomprising controlling the heat to yield greater than about 60% byweight of condensable hydrocarbons, as measured by Fischer Assay. 798.The method of claim 763, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well.799. The method of claim 798, wherein at least about 20 heat sources aredisposed in the formation for each production well.
 800. The method ofclaim 763, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,and wherein the unit of heat sources comprises a triangular pattern.801. The method of claim 763, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, wherein the unit of heat sources comprises atriangular pattern, and wherein a plurality of the units are repeatedover an area of the formation to form a repetitive pattern of units.802. A method of treating an oil shale formation in situ, comprising:providing heat from one or more heat sources to at least a portion ofthe formation; allowing the heat to transfer from the one or more heatsources to a selected section of the formation to raise an averagetemperature within the selected section to, or above, a temperature thatwill pyrolyze hydrocarbons within the selected section; controlling heatoutput from the one or more heat sources such that an average heatingrate of the selected section rises by less than about 3° C. per day whenthe average temperature of the selected section is at, or above, thetemperature that will pyrolyze hydrocarbons within the selected section;and producing a mixture from the formation.
 803. The method of claim802, wherein controlling heat output comprises: raising the averagetemperature within the selected section to a first temperature that isat or above a minimum pyrolysis temperature of hydrocarbons within theformation; limiting energy input into the one or more heat sources toinhibit increase in temperature of the selected section; and increasingenergy input into the formation to raise an average temperature of theselected section above the first temperature when production offormation fluid declines below a desired production rate.
 804. Themethod of claim 802, wherein controlling heat output comprises: raisingthe average temperature within the selected section to a firsttemperature that is at or above a minimum pyrolysis temperature ofhydrocarbons within the formation; limiting energy input into the one ormore heat sources to inhibit increase in temperature of the selectedsection; and increasing energy input into the formation to raise anaverage temperature of the selected section above the first temperaturewhen quality of formation fluid produced from the formation falls belowa desired quality.
 805. The method of claim 802, wherein the one or moreheat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section.
 806. The method ofclaim 802, wherein the one or more heat sources comprise electricalheaters.
 807. The method of claim 802, wherein the one or more heatsources comprise surface burners.
 808. The method of claim 802, whereinthe one or more heat sources comprise flameless distributed combustors.809. The method of claim 802, wherein the one or more heat sourcescomprise natural distributed combustors.
 810. The method of claim 802,further comprising controlling a pressure and a temperature within atleast a majority of the selected section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 811. The method of claim 802,wherein the heat is controlled such that an average heating rate of theselected section is less than about 1.5° C. per day during pyrolysis.812. The method of claim 802, wherein the heat is controlled such thatan average heating rate of the selected section is less than about 1° C.per day during pyrolysis.
 813. The method of claim 802, whereinproviding heat from the one or more heat sources to at least the portionof formation comprises: heating a selected volume (V) of the oil shaleformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density.
 814. Themethod of claim 802, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 815. The method of claim802, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 816. The method of claim 802, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 817. The method of claim 802, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 818.The method of claim 802, wherein the produced mixture comprisescondensable hydrocarbons, wherein the condensable hydrocarbons have anolefin content is less than about 2.5% by weight of the condensablehydrocarbons, and wherein the olefin content is greater than about 0.1%by weight of the condensable hydrocarbons.
 819. The method of claim 802,wherein the produced mixture comprises non-condensable hydrocarbons,wherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons is less than about 0.15, and wherein the ratio of ethene toethane is greater than about 0.001.
 820. The method of claim 802,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons is less than about 0.10 and wherein the ratio of ethene toethane is greater than about 0.001.
 821. The method of claim 802,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons is less than about 0.05 and wherein the ratio of ethene toethane is greater than about 0.001.
 822. The method of claim 802,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 823. The method ofclaim 802, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 824. Themethod of claim 802, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 825. Themethod of claim 802, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 826. Themethod of claim 802, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 827. The method ofclaim 802, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 828. The method of claim 802, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 829. The methodof claim 802, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 830. The method of claim802, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 831. The method of claim 802, wherein theproduced mixture comprises ammonia, and wherein greater than about 005%by weight of the produced mixture is ammonia.
 832. The method of claim802, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 833. The method of claim 802,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 834. The method of claim 802,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 835. The method ofclaim 802, wherein a partial pressure of H₂ is measured when the mixtureis at a production well.
 836. The method of claim 802, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 837. The method of claim 802, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 838. The method of claim 802, furthercomprising: providing H₂ to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 839. The method of claim 802, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 840. The method of claim 802, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 841. The methodof claim 802, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 842. The method of claim 802, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 843. The methodof claim 802, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 844. The methodof claim 843, wherein at least about 20 heat sources are disposed in theformation for each production well.
 845. The method of claim 802,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 846.The method of claim 802, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 847. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least a portion of the formation; to heata selected section of the formation to an average temperature aboveabout 270° C.; allowing the heat to transfer from the one or more heatsources to the selected section of the formation; controlling the heatfrom the one or more heat sources such that an average heating rate ofthe selected section is less than about 3° C. per day during pyrolysis;and producing a mixture from the formation.
 848. The method of claim847, wherein the one or more heat sources comprise at least two heatsources, and wherein superposition of heat from at least the two heatsources pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 849. The method of claim 847, wherein the one or moreheat sources comprise electrical heaters.
 850. The method of claim 847,further comprising supplying electricity to the electrical heaterssubstantially during non-peak hours.
 851. The method of claim 847,wherein the one or more heat sources comprise surface burners.
 852. Themethod of claim 847, wherein the one or more heat sources compriseflameless distributed combustors.
 853. The method of claim 847, whereinthe one or more heat sources comprise natural distributed combustors.854. The method of claim 847, further comprising controlling a pressureand a temperature within at least a majority of the selected section ofthe formation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.855. The method of claim 847, wherein the heat is further controlledsuch that an average heating rate of the selected section is less thanabout 3° C./day until production of condensable hydrocarbonssubstantially ceases.
 856. The method of claim 847, wherein the heat isfurther controlled such that an average heating rate of the selectedsection is less than about 1.5° C. per day during pyrolysis.
 857. Themethod of claim 847, wherein the heat is further controlled such that anaverage heating rate of the selected section is less than about 1° C.per day during pyrolysis.
 858. The method of claim 847, whereinproviding heat from the one or more heat sources to at least the portionof formation comprises: heating a selected volume (V) of the oil shaleformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density.
 859. Themethod of claim 847, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 860. The method of claim847, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 861. The method of claim 847, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 862. The method of claim 847, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 863.The method of claim 847, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 864. Themethod of claim 847, wherein the produced mixture comprisesnon-condensable hydrocarbons, wherein a molar ratio of ethene to ethanein the non-condensable hydrocarbons is less than about 0.15, and whereinthe ratio of ethene to ethane is greater than about 0.001.
 865. Themethod of claim 847, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 866.The method of claim 847, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 867. The method of claim 847, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 868. The method of claim 847, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 869. The method of claim 847, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 870. The method of claim 847, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 871. The method of claim 847, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 872. The method of claim 847, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.873. The method of claim 847, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 874. Themethod of claim 847, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 875. The method of claim 847, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 876. The method of claim 847, further comprising controllinga pressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 877. The method of claim 847, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 878. The method of claim 877, wherein the partialpressure of H₂ is measured when the mixture is at a production well.879. The method of claim 847, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 880. The methodof claim 847, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.881. The method of claim 847, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 882. The method of claim 847, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 883. Themethod of claim 847, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 884. The method of claim 847, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 885.The method of claim 847, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 886. The method of claim 847, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 887. The method of claim 886,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 888. The method of claim 847, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 889. The method of claim 847,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 890. A method of treating an oilshale formation in situ, comprising: providing heat from one or moreheat sources to at least a portion of the formation; allowing the heatto transfer from the one or more heat sources to a selected section ofthe formation; producing a mixture from the formation through at leastone production well; monitoring a temperature at or in the productionwell; and controlling heat input to raise the monitored temperature at arate of less than about 3° C. per day.
 891. The method of claim 890,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 892. The method of claim 890, wherein the one or more heatsources comprise electrical heaters.
 893. The method of claim 890,wherein the one or more heat sources comprise surface burners.
 894. Themethod of claim 890, wherein the one or more heat sources compriseflameless distributed combustors.
 895. The method of claim 890, whereinthe one or more heat sources comprise natural distributed combustors.896. The method of claim 890, further comprising controlling a pressureand a temperature within at least a majority of the selected section ofthe formation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.897. The method of claim 890, wherein the heat is controlled such thatan average heating rate of the selected section is less than about 1° C.per day during pyrolysis.
 898. The method of claim 890, whereinproviding heat from the one or more heat sources to at least the portionof formation comprises: heating a selected volume (V) of the oil shaleformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density.
 899. Themethod of claim 890, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 900. The method of claim890, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 901. The method of claim 890, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 902. The method of claim 890, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 903.The method of claim 890, wherein the produced mixture comprisesnon-condensable hydrocarbons, wherein a molar ratio of ethene to ethanein the non-condensable hydrocarbons is less than about 0.15, and whereinthe ratio of ethene to ethane is greater than about 0.001.
 904. Themethod of claim 890, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 905.The method of claim 890, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 906. The method of claim 890, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 907. The method of claim 890, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 908. The method of claim 890, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 909. The method of claim 890, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 910. The method of claim 890, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 911. The method of claim 890, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.912. The method of claim 890, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 913. Themethod of claim 890, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 914. The method of claim 890, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 915. The method of claim 890, further comprising controllinga pressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 916. The method of claim 890, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 917. The method of claim 916, wherein the partialpressure of H₂ is measured when the mixture is at a production well.918. The method of claim 890, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 919. The methodof claim 890, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.920. The method of claim 890, further comprising: providing H₂ to theheated section to hydrogenate hydrocarbons within the section; andheating a portion of the section with heat from hydrogenation.
 921. Themethod of claim 890, wherein the produced mixture comprises hydrogen andcondensable hydrocarbons, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 922. The method of claim 890, wherein allowingthe heat to transfer comprises increasing a permeability of a majorityof the selected section to greater than about 100 millidarcy.
 923. Themethod of claim 890, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 924. The method of claim 890, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 925. The methodof claim 890, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 926. The methodof claim 925, wherein at least about 20 heat sources are disposed in theformation for each production well.
 927. The method of claim 890,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 928.The method of claim 890, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 929. A method oftreating an oil shale formation in situ, comprising: heating a portionof the formation to a temperature sufficient to support oxidation ofhydrocarbons within the portion, wherein the portion is locatedsubstantially adjacent to a wellbore; flowing an oxidant through aconduit positioned within the wellbore to a heat source zone within theportion, wherein the heat source zone supports an oxidation reactionbetween hydrocarbons and the oxidant; reacting a portion of the oxidantwith hydrocarbons to generate heat; and transferring generated heatsubstantially by conduction to a pyrolysis zone of the formation topyrolyze at least a portion of the hydrocarbons within the pyrolysiszone.
 930. The method of claim 929, wherein heating the portion of theformation comprises raising a temperature of the portion above about400° C.
 931. The method of claim 929, wherein the conduit comprisescritical flow orifices, the method further comprising flowing theoxidant through the critical flow orifices to the heat source zone. 932.The method of claim 929, further comprising removing reaction productsfrom the heat source zone through the wellbore.
 933. The method of claim929, further comprising removing excess oxidant from the heat sourcezone to inhibit transport of the oxidant to the pyrolysis zone.
 934. Themethod of claim 929, further comprising transporting the oxidant fromthe conduit to the heat source zone substantially by diffusion.
 935. Themethod of claim 929, further comprising heating the conduit withreaction products being removed through the wellbore.
 936. The method ofclaim 929, wherein the oxidant comprises hydrogen peroxide.
 937. Themethod of claim 929, wherein the oxidant comprises air.
 938. The methodof claim 929, wherein the oxidant comprises a fluid substantially freeof nitrogen.
 939. The method of claim 929, further comprising limitingan amount of oxidant to maintain a temperature of the heat source zoneless than about 1200° C.
 940. The method of claim 929, wherein heatingthe portion of the formation comprises electrically heating theformation.
 941. The method of claim 929, wherein heating the portion ofthe formation comprises heating the portion using exhaust gases from asurface burner.
 942. The method of claim 929, wherein heating theportion of the formation comprises heating the portion with a flamelessdistributed combustor.
 943. The method of claim 929, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe pyrolysis zone, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.944. The method of claim 929, further comprising controlling the heatsuch that an average heating rate of the pyrolysis zone is less thanabout 1° C. per day during pyrolysis.
 945. The method of claim 929,wherein heating the portion comprises heating the pyrolysis zone suchthat a thermal conductivity of at least a portion of the pyrolysis zoneis greater than about 0.5 W/(m ° C.).
 946. The method of claim 929,further comprising controlling a pressure within at least a majority ofthe pyrolysis zone of the formation, wherein the controlled pressure isat least about 2.0 bars absolute.
 947. The method of claim 929, furthercomprising: providing hydrogen (H₂) to the pyrolysis zone to hydrogenatehydrocarbons within the pyrolysis zone; and heating a portion of thepyrolysis zone with heat from hydrogenation.
 948. The method of claim929, wherein transferring generated heat comprises increasing apermeability of a majority of the pyrolysis zone to greater than about100 millidarcy.
 949. The method of claim 929, wherein transferringgenerated heat comprises substantially uniformly increasing apermeability of a majority of the pyrolysis zone.
 950. The method ofclaim 929, wherein the heating is controlled to yield greater than about60% by weight of condensable hydrocarbons, as measured by Fischer Assay.951. The method of claim 929, wherein the wellbore is located alongstrike to reduce pressure differentials along a heated length of thewellbore.
 952. The method of claim 929, wherein the wellbore is locatedalong strike to increase uniformity of heating along a heated length ofthe wellbore.
 953. The method of claim 929, wherein the wellbore islocated along strike to increase control of heating along a heatedlength of the wellbore.
 954. A method of treating an oil shale formationin situ, comprising: heating a portion of the formation to a temperaturesufficient to support reaction of hydrocarbons within the portion of theformation with an oxidant; flowing the oxidant into a conduit, andwherein the conduit is connected such that the oxidant can flow from theconduit to the hydrocarbons; allowing the oxidant and the hydrocarbonsto react to produce heat in a heat source zone; allowing heat totransfer from the heat source zone to a pyrolysis zone in the formationto pyrolyze at least a portion of the hydrocarbons within the pyrolysiszone; and removing reaction products such that the reaction products areinhibited from flowing from the heat source zone to the pyrolysis zone.955. The method of claim 954, wherein heating the portion of theformation comprises raising the temperature of the portion above about400° C.
 956. The method of claim 954, wherein heating the portion of theformation comprises electrically heating the formation.
 957. The methodof claim 954, wherein heating the portion of the formation comprisesheating the portion using exhaust gases from a surface burner.
 958. Themethod of claim 954, wherein the conduit comprises critical floworifices, the method further comprising flowing the oxidant through thecritical flow orifices to the heat source zone.
 959. The method of claim954, wherein the conduit is located within a wellbore, wherein removingreaction products comprises removing reaction products from the heatsource zone through the wellbore.
 960. The method of claim 954, furthercomprising removing excess oxidant from the heat source zone to inhibittransport of the oxidant to the pyrolysis zone.
 961. The method of claim954, further comprising transporting the oxidant from the conduit to theheat source zone substantially by diffusion.
 962. The method of claim954, wherein the conduit is located within a wellbore, the methodfurther comprising heating the conduit with reaction products beingremoved through the wellbore to raise a temperature of the oxidantpassing through the conduit.
 963. The method of claim 954, wherein theoxidant comprises hydrogen peroxide.
 964. The method of claim 954,wherein the oxidant comprises air.
 965. The method of claim 954, whereinthe oxidant comprises a fluid substantially free of nitrogen.
 966. Themethod of claim 954, further comprising limiting an amount of oxidant tomaintain a temperature of the heat source zone less than about 1200° C.967. The method of claim 954, further comprising limiting an amount ofoxidant to maintain a temperature of the heat source zone at atemperature that inhibits production of oxides of nitrogen.
 968. Themethod of claim 954, wherein heating a portion of the formation to atemperature sufficient to support oxidation of hydrocarbons within theportion further comprises heating with a flameless distributedcombustor.
 969. The method of claim 954, further comprising controllinga pressure and a temperature within at least a majority of the pyrolysiszone of the formation, wherein the pressure is controlled as a functionof temperature, or the temperature is controlled as a function ofpressure.
 970. The method of claim 954, further comprising controllingthe heat such that an average heating rate of the pyrolysis zone is lessthan about 1° C. per day during pyrolysis.
 971. The method of claim 954,wherein allowing the heat to transfer comprises transferring heatsubstantially by conduction.
 972. The method of claim 954, whereinallowing heat to transfer comprises heating the pyrolysis zone such thata thermal conductivity of at least a portion of the pyrolysis zone isgreater than about 0.5 W/(m ° C.).
 973. The method of claim 954, furthercomprising controlling a pressure within at least a majority of thepyrolysis zone, wherein the controlled pressure is at least about 2.0bars absolute.
 974. The method of claim 954, further comprising:providing hydrogen (H₂) to the pyrolysis zone to hydrogenatehydrocarbons within the pyrolysis zone; and heating a portion of thepyrolysis zone with heat from hydrogenation.
 975. The method of claim954, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the pyrolysis zone to greater than about100 millidarcy.
 976. The method of claim 954, wherein allowing the heatto transfer comprises substantially uniformly increasing a permeabilityof a majority of the pyrolysis zone.
 977. The method of claim 954,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by Fischer Assay.978. An in situ method for heating an oil shale formation, comprising:heating a portion of the formation to a temperature sufficient tosupport reaction of hydrocarbons within the portion of the formationwith an oxidizing fluid, wherein the portion is located substantiallyadjacent to an opening in the formation; providing the oxidizing fluidto a heat source zone in the formation; allowing the oxidizing gas toreact with at least a portion of the hydrocarbons at the heat sourcezone to generate heat in the heat source zone; and transferring thegenerated heat substantially by conduction from the heat source zone toa pyrolysis zone in the formation.
 979. The method of claim 978, furthercomprising transporting the oxidizing fluid through the heat source zoneby diffusion.
 980. The method of claim 978, further comprising directingat least a portion of the oxidizing fluid into the opening throughorifices of a conduit disposed in the opening.
 981. The method of claim978, further comprising controlling a flow of the oxidizing fluid withcritical flow orifices of a conduit disposed in the opening such that arate of oxidation is controlled.
 982. The method of claim 978, wherein aconduit is disposed within the opening, the method further comprisingremoving an oxidation product from the formation through the conduit.983. The method of claim 978, wherein a conduit is disposed within theopening, the method further comprising removing an oxidation productfrom the formation through the conduit and transferring substantial heatfrom the oxidation product in the conduit to the oxidizing fluid in theconduit.
 984. The method of claim 978, wherein a conduit is disposedwithin the opening, the method further comprising removing an oxidationproduct from the formation through the conduit, wherein a flow rate ofthe oxidizing fluid in the conduit is approximately equal to a flow rateof the oxidation product in the conduit.
 985. The method of claim 978,wherein a conduit is disposed within the opening, the method furthercomprising removing an oxidation product from the formation through theconduit and controlling a pressure between the oxidizing fluid and theoxidation product in the conduit to reduce contamination of theoxidation product by the oxidizing fluid.
 986. The method of claim 978,wherein a center conduit is disposed within an outer conduit, andwherein the outer conduit is disposed within the opening, the methodfurther comprising providing the oxidizing fluid into the openingthrough the center conduit and removing an oxidation product through theouter conduit.
 987. The method of claim 978, wherein the heat sourcezone extends radially from the opening a width of less thanapproximately 0.15 m.
 988. The method of claim 978, wherein heating theportion comprises applying electrical current to an electric heaterdisposed within the opening.
 989. The method of claim 978, wherein thepyrolysis zone is substantially adjacent to the heat source zone. 990.The method of claim 978, further comprising controlling a pressure and atemperature within at least a majority of the pyrolysis zone of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.991. The method of claim 978, further comprising controlling the heatsuch that an average heating rate of the pyrolysis zone is less thanabout 1° C. per day during pyrolysis.
 992. The method of claim 978,wherein allowing the heat to transfer comprises transferring heatsubstantially by conduction.
 993. The method of claim 978, whereinallowing heat to transfer comprises heating the portion such that athermal conductivity of at least a portion of the pyrolysis zone isgreater than about 0.5 W/(m ° C.).
 994. The method of claim 978, furthercomprising controlling a pressure within at least a majority of thepyrolysis zone, wherein the controlled pressure is at least about 2.0bars absolute.
 995. The method of claim 978, further comprising:providing hydrogen (H₂) to the pyrolysis zone to hydrogenatehydrocarbons within the pyrolysis zone; and heating a portion of thepyrolysis zone with heat from hydrogenation.
 996. The method of claim978, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the pyrolysis zone to greater than about100 millidarcy.
 997. The method of claim 978, wherein allowing the heatto transfer comprises substantially uniformly increasing a permeabilityof a majority of the pyrolysis zone.
 998. The method of claim 978,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by Fischer Assay.999. A method of treating an oil shale formation in situ, comprising:providing heat from one or more heat sources to at least a portion ofthe formation; allowing the heat to transfer from the one or more heatsources to a selected section of the formation; producing a mixture fromthe formation; and maintaining an average temperature within theselected section above a minimum pyrolysis temperature and below avaporization temperature of hydrocarbons having carbon numbers greaterthan 25 to inhibit production of a substantial amount of hydrocarbonshaving carbon numbers greater than 25 in the mixture.
 1000. The methodof claim 999, wherein the one or more heat sources comprise at least twoheat sources, and wherein superposition of heat from at least the twoheat sources pyrolyzes at least some hydrocarbons within the selectedsection of the formation.
 1001. The method of claim 999, whereinmaintaining the average temperature within the selected sectioncomprises maintaining the temperature within a pyrolysis temperaturerange.
 1002. The method of claim 999, wherein the one or more heatsources comprise electrical heaters.
 1003. The method of claim 999,wherein the one or more heat sources comprise surface burners.
 1004. Themethod of claim 999, wherein the one or more heat sources compriseflameless distributed combustors.
 1005. The method of claim 999, whereinthe one or more heat sources comprise natural distributed combustors.1006. The method of claim 999, wherein the minimum pyrolysis temperatureis greater than about 270° C.
 1007. The method of claim 999, wherein thevaporization temperature is less than approximately 450° C. atatmospheric pressure.
 1008. The method of claim 999, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1009. The method of claim 999,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1010. The method of claim 999, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 1011. The method of claim 999, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 1012. The method of claim 999, wherein providing heatfrom the one or more heat sources comprises heating the selectedformation such that a thermal conductivity of at least a portion of theselected section is greater than about 0.5 W/(m ° C.).
 1013. The methodof claim 999, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 1014. Themethod of claim 999, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 1015. The method of claim 999,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 1016. The method of claim 999,wherein the produced mixture comprises non-condensable hydrocarbons,wherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons is less than about 0.15, and wherein the ratio of ethene toethane is greater than about 0.001.
 1017. The method of claim 999,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1018. The method ofclaim 999, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1019. Themethod of claim 999, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1020. Themethod of claim 999, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1021. Themethod of claim 999, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1022. The method ofclaim 999, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1023. The method of claim 999, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1024. The methodof claim 999, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1025. The method of claim999, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 1026. The method of claim 999, whereinthe produced mixture comprises ammonia, and wherein greater than about0.05% by weight of the produced mixture is ammonia.
 1027. The method ofclaim 999, wherein the produced mixture comprises ammonia, and whereinthe ammonia is used to produce fertilizer.
 1028. The method of claim999, further comprising controlling a pressure within at least amajority of the selected section of the formation, wherein thecontrolled pressure is at least about 2.0 bars absolute.
 1029. Themethod of claim 999, further comprising controlling formation conditionsto produce a mixture of condensable hydrocarbons and H₂, wherein apartial pressure of H₂ within the mixture is greater than about 0.5bars.
 1030. The method of claim 1029, wherein the partial pressure of H₂is measured when the mixture is at a production well.
 1031. The methodof claim 999, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.1032. The method of claim 999, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 1033. The method of claim 999, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1034. Themethod of claim 999, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 1035. The method of claim 999,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 1036.The method of claim 999, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 1037. The method of claim 999, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 1038. The method of claim 1037,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 1039. The method of claim 999, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 1040. The method of claim 999,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 1041. A method of treating an oilshale formation in situ, comprising: providing heat from one or moreheat sources to at least a portion of the formation; allowing the heatto transfer from the one or more heat sources to a selected section ofthe formation; controlling a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than 25; and producing a mixture from the formation.
 1042. Themethod of claim 1041, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 1043. The method of claim 1041,wherein the one or more heat sources comprise electrical heaters. 1044.The method of claim 1041, wherein the one or more heat sources comprisesurface burners.
 1045. The method of claim 1041, wherein the one or moreheat sources comprise flameless distributed combustors.
 1046. The methodof claim 1041, wherein the one or more heat sources comprise naturaldistributed combustors.
 1047. The method of claim 1041, furthercomprising controlling a temperature within at least a majority of theselected section of the formation, wherein the pressure is controlled asa function of temperature, or the temperature is controlled as afunction of pressure.
 1048. The method of claim 1047, whereincontrolling the temperature comprises maintaining a temperature withinthe selected section within a pyrolysis temperature range.
 1049. Themethod of claim 1041, further comprising controlling the heat such thatan average heating rate of the selected section is less than about 1° C.per day during pyrolysis.
 1050. The method of claim 1041, whereinproviding heat from the one or more heat sources to at least the portionof formation comprises: heating a selected volume (V) of the oil shaleformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1051. The methodof claim 1041, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1052. The method of claim1041, wherein providing heat from the one or more heat sources comprisesheating the selected formation such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1053. The method of claim 1041, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1054. The method of claim 1041, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1055.The method of claim 1041, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 1056. Themethod of claim 1041, wherein the produced mixture comprisesnon-condensable hydrocarbons, wherein a molar ratio of ethene to ethanein the non-condensable hydrocarbons is less than about 0.15, and whereinthe ratio of ethene to ethane is greater than about 0.001.
 1057. Themethod of claim 1041, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1058.The method of claim 1041, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1059. The method of claim 1041, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1060. The method of claim 1041, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1061. The method of claim 1041, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1062. The method of claim 1041, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1063. The method of claim 1041, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1064. The method of claim 1041, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1065. The method of claim 1041, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1066. The method of claim 1041, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1067. The method of claim1041, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1068. The method of claim 1041,further comprising controlling the pressure within at least a majorityof the selected section of the formation, wherein the controlledpressure is at least about 2.0 bars absolute.
 1069. The method of claim1041, further comprising controlling formation conditions to produce amixture of condensable hydrocarbons and H₂, wherein a partial pressureof H₂ within the mixture is greater than about 0.5 bars.
 1070. Themethod of claim 1069, wherein the partial pressure of H₂ is measuredwhen the mixture is at a production well.
 1071. The method of claim1041, wherein controlling formation conditions comprises recirculating aportion of hydrogen from the mixture into the formation.
 1072. Themethod of claim 1041, further comprising: providing hydrogen (H₂) to theheated section to hydrogenate hydrocarbons within the section; andheating a portion of the section with heat from hydrogenation.
 1073. Themethod of claim 1041, wherein the produced mixture comprises hydrogenand condensable hydrocarbons, the method further comprisinghydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 1074. The method of claim1041, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 1075. The method of claim 1041, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 1076. The method ofclaim 1041, further comprising controlling the heat to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured byFischer Assay.
 1077. The method of claim 1041, wherein producing themixture comprises producing the mixture in a production well, andwherein at least about 7 heat sources are disposed in the formation foreach production well.
 1078. The method of claim 1077, wherein at leastabout 20 heat sources are disposed in the formation for each productionwell.
 1079. The method of claim 1041, further comprising providing heatfrom three or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 1080. The method of claim 1041, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 1081. A method of treating an oil shaleformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; and producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 1082. The method of claim 1081, wherein the one or moreheat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.1083. The method of claim 1081, wherein the one or more heat sourcescomprise electrical heaters.
 1084. The method of claim 1081, wherein theone or more heat sources comprise surface burners.
 1085. The method ofclaim 1081, wherein the one or more heat sources comprise flamelessdistributed combustors.
 1086. The method of claim 1081, wherein the oneor more heat sources comprise natural distributed combustors.
 1087. Themethod of claim 1081, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.1088. The method of claim 1081, wherein controlling the temperaturecomprises maintaining the temperature within the selected section withina pyrolysis temperature range.
 1089. The method of claim 1081, furthercomprising controlling the heat such that an average heating rate of theselected section is less than about 1° C. per day during pyrolysis.1090. The method of claim 1081, wherein providing heat from the one ormore heat sources to at least the portion of formation comprises:heating a selected volume (V) of the oil shale formation from the one ormore heat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 1091. The method of claim 1081, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 1092. The method of claim 1081, wherein providing heat fromthe one or more heat sources comprises heating the selected formationsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 1093. The method of claim1081, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1094. The method of claim1081, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1095. The method of claim 1081,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 1096. The method of claim1081, wherein the produced mixture comprises non-condensablehydrocarbons, wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons is less than about 0.15, and wherein theratio of ethene to ethane is greater than about 0.001.
 1097. The methodof claim 1081, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1098.The method of claim 1081, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1099. The method of claim 1081, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1100. The method of claim 1081, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1101. The method of claim 1081, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1102. The method of claim 1081, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1103. The method of claim 1081, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1104. The method of claim 1081, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1105. The method of claim 1081, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1106. The method of claim 1081, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1107. The method of claim1081, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1108. The method of claim 1081,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 1109. The method of claim 1081,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1110. The method ofclaim 1109, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 1111. The method of claim 1081, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1112. The method of claim 1081, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 1113. The method of claim1081, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the section; and heating a portion ofthe section with heat from hydrogenation.
 1114. The method of claim1081, wherein the produced mixture comprises hydrogen and condensablehydrocarbons, the method further comprising hydrogenating a portion ofthe produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1115. The method of claim 1081, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1116. Themethod of claim 1081, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1117. The method of claim 1081, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 1118. The methodof claim 1081, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 1119. The methodof claim 1118, wherein at least about 20 heat sources are disposed inthe formation for each production well.
 1120. The method of claim 1081,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 1121.The method of claim 1081, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1122. A methodof treating an oil shale formation in situ, comprising: heating asection of the formation to a pyrolysis temperature from at least afirst heat source, a second heat source and a third heat source, andwherein the first heat source, the second heat source and the third heatsource are located along a perimeter of the section; controlling heatinput to the first heat source, the second heat source and the thirdheat source to limit a heating rate of the section to a rate configuredto produce a mixture from the formation with an olefin content of lessthan about 15% by weight of condensable fluids (on a dry basis) withinthe produced mixture; and producing the mixture from the formationthrough a production well.
 1123. The method of claim 1122, whereinsuperposition of heat form the first heat source, second heat source,and third heat source pyrolyzes a portion of the hydrocarbons within theformation to fluids.
 1124. The method of claim 1122, wherein thepyrolysis temperature is between about 270° C. and about 400° C. 1125.The method of claim 1122, wherein the first heat source is operated forless than about twenty-four hours a day.
 1126. The method of claim 1122,wherein the first heat source comprises an electrical heater.
 1127. Themethod of claim 1122, wherein the first heat source comprises a surfaceburner.
 1128. The method of claim 1122, wherein the first heat sourcecomprises a flameless distributed combustor.
 1129. The method of claim1122, wherein the first heat source, second heat source and third heatsource are positioned substantially at apexes of an equilateraltriangle.
 1130. The method of claim 1122, wherein the production well islocated substantially at a geometrical center of the first heat source,second heat source, and third heat source.
 1131. The method of claim1122, further comprising a fourth heat source, fifth heat source, andsixth heat source located along the perimeter of the section.
 1132. Themethod of claim 1131, wherein the heat sources are located substantiallyat apexes of a regular hexagon.
 1133. The method of claim 1132, whereinthe production well is located substantially at a center of the hexagon.1134. The method of claim 1122, further comprising controlling apressure and a temperature within at least a majority of the section ofthe formation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.1135. The method of claim 1122, wherein controlling the temperaturecomprises maintaining the temperature within the selected section withina pyrolysis temperature range.
 1136. The method of claim 1122, furthercomprising controlling the heat such that an average heating rate of thesection is less than about 3° C. per day during pyrolysis.
 1137. Themethod of claim 1122, further comprising controlling the heat such thatan average heating rate of the section is less than about 1° C. per dayduring pyrolysis.
 1138. The method of claim 1122, wherein providing heatfrom the one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 1139. The method of claim 1122, whereinheating the section of the formation comprises transferring heatsubstantially by conduction.
 1140. The method of claim 1122, whereinproviding heat from the one or more heat sources comprises heating thesection such that a thermal conductivity of at least a portion of thesection is greater than about 0.5 W/(m ° C.).
 1141. The method of claim1122, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1142. The method of claim1122, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1143. The method of claim 1122,wherein the produced mixture comprises non-condensable hydrocarbons,wherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons is less than about 0.15, and wherein the ratio of ethene toethane is greater than about 0.001.
 1144. The method of claim 1122,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1145. The method ofclaim 1122, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1146. Themethod of claim 1122, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1147. Themethod of claim 1122, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1148. Themethod of claim 1122, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1149. The method ofclaim 1122, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1150. The method of claim 1122, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1151. The methodof claim 1122, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1152. The method of claim1122, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1153. The method ofclaim 1122, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1154. The method of claim 1122, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1155.The method of claim 1122, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1156. The method of claim 1122, further comprising controlling formationconditions to produce a mixture of condensable hydrocarbons and H₂,wherein a partial pressure of H₂ within the mixture is greater thanabout 0.5 bars.
 1157. The method of claim 1156, wherein the partialpressure of H₂ is measured when the mixture is at a production well.1158. The method of claim 1122, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 1159. The methodof claim 1122, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.1160. The method of claim 1122, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 1161. The method of claim 1122, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1162. Themethod of claim 1122, wherein heating the section comprises increasing apermeability of a majority of the section to greater than about 100millidarcy.
 1163. The method of claim 1122, wherein heating the sectioncomprises substantially uniformly increasing a permeability of amajority of the section.
 1164. The method of claim 1122, furthercomprising controlling the heat to yield greater than about 60% byweight of condensable hydrocarbons, as measured by Fischer Assay. 1165.The method of claim 1122, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well.1166. The method of claim 1165, wherein at least about 20 heat sourcesare disposed in the formation for each production well.
 1167. The methodof claim 1122, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,and wherein the unit of heat sources comprises a triangular pattern.1168. The method of claim 1122, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, wherein the unit of heat sources comprises atriangular pattern, and wherein a plurality of the units are repeatedover an area of the formation to form a repetitive pattern of units.1169. A method of treating an oil shale formation in situ, comprising:providing heat from one or more heat sources to at least a portion ofthe formation; allowing the heat to transfer from the one or more heatsources to a selected section of the formation; and producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1170.The method of claim 1169, wherein the one or more heat sources compriseat least two heat sources, and wherein superposition of heat from atleast the two heat sources pyrolyzes at least some hydrocarbons withinthe selected section of the formation.
 1171. The method of claim 1169,wherein the one or more heat sources comprise electrical heaters. 1172.The method of claim 1169, wherein the one or more heat sources comprisesurface burners.
 1173. The method of claim 1169, wherein the one or moreheat sources comprise flameless distributed combustors.
 1174. The methodof claim 1169, wherein the one or more heat sources comprise naturaldistributed combustors.
 1175. The method of claim 1169, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1176. The method of claim 1175,wherein controlling the temperature comprises maintaining thetemperature within the selected section within a pyrolysis temperaturerange.
 1177. The method of claim 1169, further comprising controllingthe heat such that an average heating rate of the selected section isless than about 1° C. per day during pyrolysis.
 1178. The method ofclaim 1169, wherein providing heat from the one or more heat sources toat least the portion of formation comprises: heating a selected volume(V) of the oil shale formation from the one or more heat sources,wherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./day.1179. The method of claim 1169, wherein allowing the heat to transfercomprises transferring heat substantially by conduction.
 1180. Themethod of claim 1169, wherein providing heat from the one or more heatsources comprises heating the selected formation such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1181. The method of claim 1169, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 1182. The method of claim 1169, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1183. The method of claim 1169, wherein theproduced mixture comprises non-condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the non-condensablehydrocarbons are olefins.
 1184. The method of claim 1169, wherein theproduced mixture comprises non-condensable hydrocarbons, wherein a molarratio of ethene to ethane in the non-condensable hydrocarbons is lessthan about 0.15, and wherein the ratio of ethene to ethane is greaterthan about 0.001.
 1185. The method of claim 1169, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 1186. The method of claim 1169, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 1187. The method of claim 1169,wherein the produced mixture comprises condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 1188. The method of claim1169, wherein the produced mixture comprises condensable hydrocarbons,and wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 1189. The method of claim 1169,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 1190. Themethod of claim 1169, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 1191. The method of claim1169, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 1192. The method of claim 1169, whereinthe produced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1193. The method of claim 1169, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1194. The method of claim1169, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1195. The method of claim 1169,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 1196. The method of claim 1169,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1197. The method ofclaim 1196, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 1198. The method of claim 1169, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1199. The method of claim 1169, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 1200. The method of claim1169, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the section; and heating a portion ofthe section with heat from hydrogenation.
 1201. The method of claim1169, wherein the produced mixture comprises hydrogen and condensablehydrocarbons, the method further comprising hydrogenating a portion ofthe produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1202. The method of claim 1169, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1203. Themethod of claim 1169, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1204. The method of claim 1169, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 1205. The methodof claim 1169, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 1206. The methodof claim 1205, wherein at least about 20 heat sources are disposed inthe formation for each production well.
 1207. The method of claim 1169,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 1208.The method of claim 1169, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1209. A methodof treating an oil shale formation in situ, comprising: providing heatfrom one or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; and producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1210. Themethod of claim 1209, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 1211. The method of claim 1209,wherein the one or more heat sources comprise electrical heaters. 1212.The method of claim 1209, wherein the one or more heat sources comprisesurface burners.
 1213. The method of claim 1209, wherein the one or moreheat sources comprise flameless distributed combustors.
 1214. The methodof claim 1209, wherein the one or more heat sources comprise naturaldistributed combustors.
 1215. The method of claim 1209, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1216. The method of claim 1215,wherein controlling the temperature comprises maintaining thetemperature within the selected section within a pyrolysis temperaturerange.
 1217. The method of claim 1209, further comprising controllingthe heat such that an average heating rate of the selected section isless than about 1° C. per day during pyrolysis.
 1218. The method ofclaim 1209, wherein providing heat from the one or more heat sources toat least the portion of formation comprises: heating a selected volume(V) of the oil shale formation from the one or more heat sources,wherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./day.1219. The method of claim 1209, wherein allowing the heat to transfercomprises transferring heat substantially by conduction.
 1220. Themethod of claim 1209, wherein providing heat from the one or more heatsources comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1221. The method of claim 1209, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 1222. The method of claim 1209, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1223. The method of claim 1209, wherein theproduced mixture comprises non-condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the non-condensablehydrocarbons are olefins.
 1224. The method of claim 1209, wherein theproduced mixture comprises non-condensable hydrocarbons, wherein a molarratio of ethene to ethane in the non-condensable hydrocarbons is lessthan about 0.15, and wherein the ratio of ethene to ethane is greaterthan about 0.001.
 1225. The method of claim 1209, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1226. The method of claim 1209, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1227. The method of claim 1209,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1228. The method ofclaim 1209, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1229. Themethod of claim 1209, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1230. The method ofclaim 1209, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1231. The method of claim 1209, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1232. The methodof claim 1209, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1233. The method of claim1209, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1234. The method ofclaim 1209, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1235. The method of claim 1209, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1236.The method of claim 1209, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1237. The method of claim 1209, further comprising controlling formationconditions to produce a mixture of condensable hydrocarbons and H₂,wherein a partial pressure of H₂ within the mixture is greater thanabout 0.5 bars.
 1238. The method of claim 1237, wherein the partialpressure of H₂ is measured when the mixture is at a production well.1239. The method of claim 1209, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 1240. The methodof claim 1209, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.1241. The method of claim 1209, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 1242. The method of claim 1209, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1243. Themethod of claim 1209, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 1244. The method of claim 1209,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 1245.The method of claim 1209, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 1246. The method of claim 1209, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 1247. The method of claim 1246,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 1248. The method of claim 1209, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 1249. The method of claim 1209,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 1250. A method of treating an oilshale formation in situ, comprising: providing heat from one or moreheat sources to at least a portion of the formation; allowing the heatto transfer from the one or more heat sources to a selected section ofthe formation; and producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 1251. The method of claim 1250,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 1252. The method of claim 1250, wherein the one or more heatsources comprise electrical heaters.
 1253. The method of claim 1250,wherein the one or more heat sources comprise surface burners.
 1254. Themethod of claim 1250, wherein the one or more heat sources compriseflameless distributed combustors.
 1255. The method of claim 1250,wherein the one or more heat sources comprise natural distributedcombustors.
 1256. The method of claim 1250, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1257. The method of claim 1256,wherein controlling the temperature comprises maintaining thetemperature within the selected section within a pyrolysis temperaturerange.
 1258. The method of claim 1250, further comprising controllingthe heat such that an average heating rate of the selected section isless than about 1° C. per day during pyrolysis.
 1259. The method ofclaim 1250, wherein providing heat from the one or more heat sources toat least the portion of formation comprises: heating a selected volume(V) of the oil shale formation from the one or more heat sources,wherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./day.1260. The method of claim 1250, wherein allowing the heat to transfercomprises transferring heat substantially by conduction.
 1261. Themethod of claim 1250, wherein providing heat from the one or more heatsources comprises heating the selected formation such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1262. The method of claim 1250, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 1263. The method of claim 1250, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1264. The method of claim 1250, wherein theproduced mixture comprises non-condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the non-condensablehydrocarbons are olefins.
 1265. The method of claim 1250, wherein theproduced mixture comprises non-condensable hydrocarbons, wherein a molarratio of ethene to ethane in the non-condensable hydrocarbons is lessthan about 0.15, and wherein the ratio of ethene to ethane is greaterthan about 0.001.
 1266. The method of claim 1250, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1267. The method of claim 1250, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1268. The method of claim 1250,wherein the produced mixture comprises condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 1269. The method of claim1250, wherein the produced mixture comprises condensable hydrocarbons,and wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 1270. The method of claim 1250,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 1271. Themethod of claim 1250, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 1272. The method of claim1250, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 1273. The method of claim 1250, whereinthe produced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1274. The method of claim 1250, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1275. The method of claim1250, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1276. The method of claim 1250,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 1277. The method of claim 1250,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1278. The method ofclaim 1277, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 1279. The method of claim 1250, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1280. The method of claim 1250, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 1281. The method of claim1250, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the section; and heating a portion ofthe section with heat from hydrogenation.
 1282. The method of claim1250, wherein the produced mixture comprises hydrogen and condensablehydrocarbons, the method further comprising hydrogenating a portion ofthe produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1283. The method of claim 1250, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1284. Themethod of claim 1250, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1285. The method of claim 1250, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 1286. The methodof claim 1250, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 1287. The methodof claim 1286, wherein at least about 20 heat sources are disposed inthe formation for each production well.
 1288. The method of claim 1250,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 1289.The method of claim 1250, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1290. A methodof treating an oil shale formation in situ, comprising: raising atemperature of a first section of the formation with one or more heatsources to a first pyrolysis temperature; heating the first section toan upper pyrolysis temperature, wherein heat is supplied to the firstsection at a rate configured to inhibit olefin production; producing afirst mixture from the formation, wherein the first mixture comprisescondensable hydrocarbons and H₂; creating a second mixture from thefirst mixture, wherein the second mixture comprises a higherconcentration of H₂ than the first mixture; raising a temperature of asecond section of the formation with one or more heat sources to asecond pyrolysis temperature; providing a portion of the second mixtureto the second section; heating the second section to an upper pyrolysistemperature, wherein heat is supplied to the second section at a rateconfigured to inhibit olefin production; and producing a third mixturefrom the second section.
 1291. The method of claim 1290, whereincreating the second mixture comprises removing condensable hydrocarbonsfrom the first mixture.
 1292. The method of claim 1290, wherein creatingthe second mixture comprises removing water from the first mixture.1293. The method of claim 1290, wherein creating the second mixturecomprises removing carbon dioxide from the first mixture.
 1294. Themethod of claim 1290, wherein the first pyrolysis temperature is greaterthan about 270° C.
 1295. The method of claim 1290, wherein the secondpyrolysis temperature is greater than about 270° C.
 1296. The method ofclaim 1290, wherein the upper pyrolysis temperature is about 500° C.1297. The method of claim 1290, wherein the one or more heat sourcescomprise at least two heat sources, and wherein superposition of heatfrom at least the two heat sources pyrolyzes at least some hydrocarbonswithin the first or second selected section of the formation.
 1298. Themethod of claim 1290, wherein the one or more heat sources compriseelectrical heaters.
 1299. The method of claim 1290, wherein the one ormore heat sources comprise surface burners.
 1300. The method of claim1290, wherein the one or more heat sources comprise flamelessdistributed combustors.
 1301. The method of claim 1290, wherein the oneor more heat sources comprise natural distributed combustors.
 1302. Themethod of claim 1290, further comprising controlling a pressure and atemperature within at least a majority of the first section and thesecond section of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 1303. The method of claim 1290, further comprisingcontrolling the heat to the first and second sections such that anaverage heating rate of the first and second sections is less than about1° C. per day during pyrolysis.
 1304. The method of claim 1290, whereinheating the first and the second sections comprises: heating a selectedvolume (V) of the oil shale formation from the one or more heat sources,wherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./day.1305. The method of claim 1290, wherein heating the first and secondsections comprises transferring heat substantially by conduction. 1306.The method of claim 1290, wherein heating the first and second sectionscomprises heating the first and second sections such that a thermalconductivity of at least a portion of the first and second sections isgreater than about 0.5 W/(m ° C.).
 1307. The method of claim 1290,wherein the first or third mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1308. The method of claim1290, wherein the first or third mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 1309. The method of claim1290, wherein the first or third mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.1310. The method of claim 1290, wherein the first or third mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1311. The method of claim 1290, wherein thefirst or third mixture comprises condensable hydrocarbons, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1312. The method of claim 1290,wherein the first or third mixture comprises condensable hydrocarbons,and wherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1313. The method ofclaim 1290, wherein the first or third mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1314. Themethod of claim 1290, wherein the first or third mixture comprisescondensable hydrocarbons, and wherein greater than about 20% by weightof the condensable hydrocarbons are aromatic compounds.
 1315. The methodof claim 1290, wherein the first or third mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1316. The method of claim 1290, wherein the first or thirdmixture comprises condensable hydrocarbons, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 1317.The method of claim 1290, wherein the first or third mixture comprisescondensable hydrocarbons, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 1318. Themethod of claim 1290, wherein the first or third mixture comprises anon-condensable component, and wherein the non-condensable componentcomprises hydrogen, and wherein the hydrogen is greater than about 10%by volume of the non-condensable component and wherein the hydrogen isless than about 80% by volume of the non-condensable component. 1319.The method of claim 1290, wherein the first or third mixture comprisesammonia, and wherein greater than about 0.05% by weight of the producedmixture is ammonia.
 1320. The method of claim 1290, wherein the first orthird mixture comprises ammonia, and wherein the ammonia is used toproduce fertilizer.
 1321. The method of claim 1290, further comprisingcontrolling a pressure within at least a majority of the first or secondsections of the formation, wherein the controlled pressure is at leastabout 2.0 bars absolute.
 1322. The method of claim 1290, furthercomprising controlling formation conditions to produce a mixture ofcondensable hydrocarbons and H₂, wherein a partial pressure of H₂ withinthe mixture is greater than about 0.5 bars.
 1323. The method of claim1322, wherein the partial pressure of H₂ within a mixture is measuredwhen the mixture is at a production well.
 1324. The method of claim1290, further comprising altering a pressure within the formation toinhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1325. The method of claim 1290, furthercomprising: providing hydrogen (H₂) to the first or second section tohydrogenate hydrocarbons within the first or second section; and heatinga portion of the first or second section with heat from hydrogenation.1326. The method of claim 1290, further comprising: producing hydrogenand condensable hydrocarbons from the formation; and hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 1327. The method of claim 1290, furthercomprising increasing a permeability of a majority of the first orsecond section to greater than about 100 millidarcy.
 1328. The method ofclaim 1290, further comprising substantially uniformly increasing apermeability of a majority of the first or second section.
 1329. Themethod of claim 1290, wherein the heating is controlled to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured byFischer Assay.
 1330. The method of claim 1290, wherein producing thefirst or third mixture comprises producing the first or third mixture ina production well, and wherein at least about 7 heat sources aredisposed in the formation for each production well.
 1331. The method ofclaim 1330, wherein at least about 20 heat sources are disposed in theformation for each production well.
 1332. The method of claim 1290,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 1333.The method of claim 1290, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1334. A methodof treating an oil shale formation in situ, comprising: providing heatfrom one or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; producing a mixture from theformation; and hydrogenating a portion of the produced mixture with H₂produced from the formation.
 1335. The method of claim 1334, wherein theone or more heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.1336. The method of claim 1334, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 1337. The method of claim 1334, wherein the one or more heatsources comprise electrical heaters.
 1338. The method of claim 1334,wherein the one or more heat sources comprise surface burners.
 1339. Themethod of claim 1334, wherein the one or more heat sources compriseflameless distributed combustors.
 1340. The method of claim 1334,wherein the one or more heat sources comprise natural distributedcombustors.
 1341. The method of claim 1334, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1342. The method of claim 1334,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1343. The method of claim 1334, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 1344. The method of claim 1334, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 1345. The method of claim 1334, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 1346. The method of claim1334, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1347. The method of claim1334, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1348. The method of claim 1334,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 1349. The method ofclaim 1334, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1350.The method of claim 1334, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1351. The method of claim 1334, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1352. The method of claim 1334, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1353. The method of claim 1334, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1354. The method of claim 1334, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1355. The method of claim 1334, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1356. The method of claim 1334, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1357. The method of claim 1334, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1358. The method of claim 1334, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1359. The method of claim1334, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1360. The method of claim 1334,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 1361. The method of claim 1334,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 1362. The method of claim 1334, wherein a partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 1363. The method of claim 1334, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 1364. The method of claim 1334, further comprising: providinghydrogen (H₂) to the heated section to hydrogenate hydrocarbons withinthe section; and heating a portion of the section with heat fromhydrogenation.
 1365. The method of claim 1334, wherein allowing the heatto transfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 1366. The methodof claim 1334, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1367. The method of claim 1334, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 1368. The methodof claim 1334, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 1369. The methodof claim 1368, wherein at least about 20 heat sources are disposed inthe formation for each production well.
 1370. The method of claim 1334,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 1371.The method of claim 1334, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1372. A methodof treating an oil shale formation in situ, comprising: heating a firstsection of the formation; producing H₂ from the first section offormation; heating a second section of the formation; and recirculatinga portion of the H₂ from the first section into the second section ofthe formation to provide a reducing environment within the secondsection of the formation.
 1373. The method of claim 1372, whereinheating the first section or heating the second section comprisesheating with an electrical heater.
 1374. The method of claim 1372,wherein heating the first section or heating the second sectioncomprises heating with a surface burner.
 1375. The method of claim 1372,wherein heating the first section or heating the second sectioncomprises heating with a flameless distributed combustor.
 1376. Themethod of claim 1372, wherein heating the first section or heating thesecond section comprises heating with a natural distributed combustor.1377. The method of claim 1372, further comprising controlling apressure and a temperature within at least a majority of the first orsecond section of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 1378. The method of claim 1372, further comprisingcontrolling the heat such that an average heating rate of the first orsecond section is less than about 1° C. per day during pyrolysis. 1379.The method of claim 1372, wherein heating the first section or heatingthe second section further comprises: heating a selected volume (V) ofthe oil shale formation from the one or more heat sources, wherein theformation has an average heat capacity (C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day provided to the volume isequal to or less than Pwr, wherein Pwr is calculated by the equation:Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is anaverage heating rate of the formation, ρ_(B) is formation bulk density,and wherein the heating rate is less than about 10° C./day.
 1380. Themethod of claim 1372, wherein heating the first section or heating thesecond section comprises transferring heat substantially by conduction.1381. The method of claim 1372, wherein heating the first section orheating the second section comprises heating the formation such that athermal conductivity of at least a portion of the first or secondsection is greater than about 0.5 W/(m ° C.).
 1382. The method of claim1372, further comprising producing a mixture from the second section,wherein the produced mixture comprises condensable hydrocarbons havingan API gravity of at least about 25°.
 1383. The method of claim 1372,further comprising producing a mixture from the second section, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1384. The method of claim 1372, furthercomprising producing a mixture from the second section, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 1385. The method of claim 1372,further comprising producing a mixture from the second section, whereinthe produced mixture comprises condensable hydrocarbons, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 1386. The method of claim 1372,further comprising producing a mixture from the second section, whereinthe produced mixture comprises condensable hydrocarbons, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1387. The method of claim 1372,further comprising producing a mixture from the second section, whereinthe produced mixture comprises condensable hydrocarbons, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 1388. The method of claim 1372,further comprising producing a mixture from the second section, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 1389. The method of claim1372, further comprising producing a mixture from the second section,wherein the produced mixture comprises condensable hydrocarbons, andwherein greater than about 20% by weight of the condensable hydrocarbonsare aromatic compounds.
 1390. The method of claim 1372, furthercomprising producing a mixture from the second section, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 5% by weight of the condensable hydrocarbons comprisesmulti-ring aromatics with more than two rings.
 1391. The method of claim1372, further comprising producing a mixture from the second section,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 0.3% by weight of the condensable hydrocarbonsare asphaltenes.
 1392. The method of claim 1372, further comprisingproducing a mixture from the second section, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1393. The method of claim 1372, further comprisingproducing a mixture from the second section, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1394. The method of claim 1372, furthercomprising producing a mixture from the second section, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1395. The method of claim1372, further comprising producing a mixture from the second section,wherein the produced mixture comprises ammonia, and wherein the ammoniais used to produce fertilizer.
 1396. The method of claim 1372, furthercomprising controlling a pressure within at least a majority of thefirst or second section of the formation, wherein the controlledpressure is at least about 2.0 bars absolute.
 1397. The method of claim1372, further comprising controlling formation conditions to produce amixture of condensable hydrocarbons and H₂, wherein a partial pressureof H₂ within the mixture is greater than about 0.5 bars.
 1398. Themethod of claim 1397, wherein the partial pressure of H₂ within amixture is measured when the mixture is at a production well.
 1399. Themethod of claim 1372, further comprising altering a pressure within theformation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than about
 25. 1400. The method of claim1372, further comprising: providing hydrogen (H₂) to the second sectionto hydrogenate hydrocarbons within the section; and heating a portion ofthe second section with heat from hydrogenation.
 1401. The method ofclaim 1372, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1402. The method of claim 1372, wherein heating thefirst section or heating the second section comprises increasing apermeability of a majority of the first or second section, respectively,to greater than about 100 millidarcy.
 1403. The method of claim 1372,wherein heating the first section or heating the second sectioncomprises substantially uniformly increasing a permeability of amajority of the first or second section, respectively.
 1404. The methodof claim 1372, further comprising controlling the heating of the firstsection or controlling the heat of the second section to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured byFischer Assay.
 1405. The method of claim 1372, further comprisingproducing a mixture from the formation in a production well, and whereinat least about 7 heat sources are disposed in the formation for eachproduction well.
 1406. The method of claim 1405, wherein at least about20 heat sources are disposed in the formation for each production well.1407. The method of claim 1372, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 1408. The method of claim 1372, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 1409. A method of treating an oil shaleformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; producing a mixture from the formation; and controllingformation conditions such that the mixture produced from the formationcomprises condensable hydrocarbons including H₂, wherein a partialpressure of H₂ within the mixture is greater than about 0.5 bars. 1410.The method of claim 1409, wherein the one or more heat sources compriseat least two heat sources, and wherein superposition of heat from atleast the two heat sources pyrolyzes at least some hydrocarbons withinthe selected section of the formation.
 1411. The method of claim 1409,wherein controlling formation conditions comprises maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 1412. The method of claim 1409, wherein the one or more heatsources comprise electrical heaters.
 1413. The method of claim 1409,wherein the one or more heat sources comprise surface burners.
 1414. Themethod of claim 1409, wherein the one or more heat sources compriseflameless distributed combustors.
 1415. The method of claim 1409,wherein the one or more heat sources comprise natural distributedcombustors.
 1416. The method of claim 1409, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1417. The method of claim 1409,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1418. The method of claim 1409, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 1419. The method of claim 1409, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 1420. The method of claim 1409, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 1421. The method of claim1409, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1422. The method of claim1409, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1423. The method of claim 1409,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 1424. The method ofclaim 1409, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1425.The method of claim 1409, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1426. The method of claim 1409, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1427. The method of claim 1409, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1428. The method of claim 1409, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1429. The method of claim 1409, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1430. The method of claim 1409, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1431. The method of claim 1409, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1432. The method of claim 1409, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1433. The method of claim 1409, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1434. The method of claim1409, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1435. The method of claim 1409,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 1436. The method of claim 1409,further comprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1437. The method of claim 1409, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 1438. The method of claim1409, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the section; and heating a portion ofthe section with heat from hydrogenation.
 1439. The method of claim1409, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1440. The method of claim 1409, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1441. Themethod of claim 1409, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1442. The method of claim 1409, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 1443. The methodof claim 1409, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 1444. The methodof claim 1443, wherein at least about 20 heat sources are disposed inthe formation for each production well.
 1445. The method of claim 1409,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 1446.The method of claim 1409, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1447. The methodof claim 1409, wherein a partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1448. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; maintaining a pressure of theselected section above atmospheric pressure to increase a partialpressure of H₂, as compared to the partial pressure of H₂ at atmosphericpressure, in at least a majority of the selected section; and producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons having an API gravity of at least about 25°.1449. The method of claim 1448, wherein the one or more heat sourcescomprise at least two heat sources, and wherein superposition of heatfrom at least the two heat sources pyrolyzes at least some hydrocarbonswithin the selected section of the formation.
 1450. The method of claim1448, further comprising maintaining a temperature within the selectedsection within a pyrolysis temperature range.
 1451. The method of claim1448, wherein the one or more heat sources comprise electrical heaters.1452. The method of claim 1448, wherein the one or more heat sourcescomprise surface burners.
 1453. The method of claim 1448, wherein theone or more heat sources comprise flameless distributed combustors.1454. The method of claim 1448, wherein the one or more heat sourcescomprise natural distributed combustors.
 1455. The method of claim 1448,further comprising controlling the pressure and a temperature within atleast a majority of the selected section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 1456. The method of claim 1448,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1457. The method of claim 1448, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 1458. The method of claim 1448, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 1459. The method of claim 1448, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 1460. The method of claim1448, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1461. The method of claim 1448,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 1462. The method ofclaim 1448, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1463.The method of claim 1448, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1464. The method of claim 1448, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1465. The method of claim 1448, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1466. The method of claim 1448, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1467. The method of claim 1448, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1468. The method of claim 1448, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1469. The method of claim 1448, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1470. The method of claim 1448, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1471. The method of claim 1448, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1472. The method of claim1448, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1473. The method of claim 1448,further comprising controlling the pressure within at least a majorityof the selected section of the formation, wherein the controlledpressure is at least about 2.0 bars absolute.
 1474. The method of claim1448, further comprising increasing the pressure of the selectedsection, to an upper limit of about 21 bars absolute, to increase anamount of non-condensable hydrocarbons produced from the formation.1475. The method of claim 1448, further comprising decreasing pressureof the selected section, to a lower limit of about atmospheric pressure,to increase an amount of condensable hydrocarbons produced from theformation.
 1476. The method of claim 1448, wherein a partial pressurecomprises a partial pressure based on properties measured at aproduction well.
 1477. The method of claim 1448, further comprisingaltering the pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 1478. The method of claim 1448, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 1479. The method of claim 1448, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 1480. The method of claim 1448, furthercomprising: producing hydrogen and condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1481. Themethod of claim 1448, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 1482. The method of claim 1448,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 1483.The method of claim 1448, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 1484. The method of claim 1448, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 1485. The method of claim 1484,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 1486. The method of claim 1448, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 1487. The method of claim 1448,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 1488. A method of treating an oilshale formation in situ, comprising: providing heat from one or moreheat sources to at least a portion of the formation; allowing the heatto transfer from the one or more heat sources to a selected section ofthe formation; providing H₂ to the formation to produce a reducingenvironment in at least some of the formation; producing a mixture fromthe formation.
 1489. The method of claim 1488, wherein the one or moreheat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.1490. The method of claim 1488, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 1491. The method of claim 1488, further comprising separating aportion of hydrogen within the mixture and recirculating the portioninto the formation.
 1492. The method of claim 1488, wherein the one ormore heat sources comprise electrical heaters.
 1493. The method of claim1488, wherein the one or more heat sources comprise surface burners.1494. The method of claim 1488, wherein the one or more heat sourcescomprise flameless distributed combustors.
 1495. The method of claim1488, wherein the one or more heat sources comprise natural distributedcombustors.
 1496. The method of claim 1488, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1497. The method of claim 1488,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1498. The method of claim 1488, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 1499. The method of claim 1488, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 1500. The method of claim 1488, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 1501. The method of claim1488, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1502. The method of claim1488, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1503. The method of claim 1488,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 1504. The method ofclaim 1488, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1505.The method of claim 1488, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1506. The method of claim 1488, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1507. The method of claim 1488, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1508. The method of claim 1488, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1509. The method of claim 1488, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1510. The method of claim 1488, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1511. The method of claim 1488, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1512. The method of claim 1488, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1513. The method of claim 1488, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1514. The method of claim1488, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1515. The method of claim 1488,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 1516. The method of claim 1488,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 1517. The method of claim 1488, wherein a partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 1518. The method of claim 1488, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 1519. The method of claim 1488, wherein providing hydrogen (H₂) tothe formation further comprises: hydrogenating hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 1520. The method of claim 1488, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 1521. The method of claim1488, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 1522. The method of claim 1488, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 1523. The method ofclaim 1488, further comprising controlling the heat to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured byFischer Assay.
 1524. The method of claim 1488, wherein producing themixture comprises producing the mixture in a production well, andwherein at least about 7 heat sources are disposed in the formation foreach production well.
 1525. The method of claim 1524, wherein at leastabout 20 heat sources are disposed in the formation for each productionwell.
 1526. The method of claim 1488, further comprising providing heatfrom three or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 1527. The method of claim 1488, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 1528. A method of treating an oil shaleformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; providing H₂ to the selected section to hydrogenatehydrocarbons within the selected section and to heat a portion of thesection with heat from the hydrogenation; and controlling heating of theselected section by controlling amounts of H₂ provided to the selectedsection.
 1529. The method of claim 1528, wherein the one or more heatsources comprise at least two heat sources, and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 1530. Themethod of claim 1528, further comprising maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 1531.The method of claim 1528, wherein the one or more heat sources compriseelectrical heaters.
 1532. The method of claim 1528, wherein the one ormore heat sources comprise surface burners.
 1533. The method of claim1528, wherein the one or more heat sources comprise flamelessdistributed combustors.
 1534. The method of claim 1528, wherein the oneor more heat sources comprise natural distributed combustors.
 1535. Themethod of claim 1528, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.1536. The method of claim 1528, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 1537. The method of claim 1528,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of the oilshale formation from the one or more heat sources, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day provided to the volume is equal to orless than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1538. The methodof claim 1528, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1539. The method of claim1528, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1540. The method of claim 1528, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons having an API gravity of at least about 25°.1541. The method of claim 1528, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 1542. The method of claim1528, further comprising producing a mixture from the formation, whereinthe produced mixture comprises non-condensable hydrocarbons, and whereina molar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 1543. The method of claim 1528,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 1544. The method of claim 1528,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1545. The method of claim 1528,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 1546. The method of claim 1528,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1547. The method of claim 1528, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 1548.The method of claim 1528, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1549. The method of claim 1528, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 1550. The method of claim1528, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 1551. The method of claim 1528, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1552. The method of claim 1528, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 1553. The method of claim1528, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 1554. The method of claim 1528, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 1555. The method of claim 1528, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bars.
 1556. The method of claim 1555, wherein thepartial pressure of H₂ within the mixture is measured when the mixtureis at a production well.
 1557. The method of claim 1528, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1558. The method of claim 1528, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from a produced mixture into the formation.
 1559. The methodof claim 1528, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1560. The method of claim 1528, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1561. Themethod of claim 1528, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1562. The method of claim 1528, further comprisingproducing a mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well.1563. The method of claim 1562, wherein at least about 20 heat sourcesare disposed in the formation for each production well.
 1564. The methodof claim 1528, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,and wherein the unit of heat sources comprises a triangular pattern.1565. The method of claim 1528, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, wherein the unit of heat sources comprises atriangular pattern, and wherein a plurality of the units are repeatedover an area of the formation to form a repetitive pattern of units.1566. An in situ method for producing H₂ from an oil shale formation,comprising: providing heat from one or more heat sources to at least aportion of the formation; allowing the heat to transfer from the one ormore heat sources to a selected section of the formation; and producinga mixture from the formation, wherein a H₂ partial pressure within themixture is greater than about 0.5 bars.
 1567. The method of claim 1566,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 1568. The method of claim 1566, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 1569. The method of claim 1566, wherein the one ormore heat sources comprise electrical heaters.
 1570. The method of claim1566, wherein the one or more heat sources comprise surface burners.1571. The method of claim 1566, wherein the one or more heat sourcescomprise flameless distributed combustors.
 1572. The method of claim1566, wherein the one or more heat sources comprise natural distributedcombustors.
 1573. The method of claim 1566, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1574. The method of claim 1566,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1575. The method of claim 1566, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 1576. The method of claim 1566, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 1577. The method of claim 1566, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 1578. The method of claim1566, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1579. The method of claim1566, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1580. The method of claim 1566,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 1581. The method ofclaim 1566, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1582.The method of claim 1566, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1583. The method of claim 1566, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1584. The method of claim 1566, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1585. The method of claim 1566, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1586. The method of claim 1566, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1587. The method of claim 1566, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1588. The method of claim 1566, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1589. The method of claim 1566, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1590. The method of claim 1566, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1591. The method of claim1566, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1592. The method of claim 1566,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 1593. The method of claim 1566,further comprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1594. The method of claim 1566, furthercomprising recirculating a portion of the hydrogen within the mixtureinto the formation.
 1595. The method of claim 1566, further comprisingcondensing a hydrocarbon component from the produced mixture andhydrogenating the condensed hydrocarbons with a portion of the hydrogen.1596. The method of claim 1566, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 1597. The method of claim 1566, wherein allowing the heatto transfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 1598. The methodof claim 1566, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1599. The method of claim 1566, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 1600. The methodof claim 1566, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 1601. The methodof claim 1600, wherein at least about 20 heat sources are disposed inthe formation for each production well.
 1602. The method of claim 1566,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 1603.The method of claim 1566, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1604. The methodof claim 1566, wherein a partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1605. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; wherein the selected section has beenselected for heating using an atomic hydrogen weight percentage of atleast a portion of hydrocarbons in the selected section, and wherein atleast the portion of the hydrocarbons in the selected section comprisesan atomic hydrogen weight percentage, when measured on a dry, ash-freebasis, of greater than about 4.0%; and producing a mixture from theformation.
 1606. The method of claim 1605, wherein the one or more heatsources comprise at least two heat sources, and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 1607. Themethod of claim 1605, further comprising maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 1608.The method of claim 1605, wherein the one or more heat sources compriseelectrical heaters.
 1609. The method of claim 1605, wherein the one ormore heat sources comprise surface burners.
 1610. The method of claim1605, wherein the one or more heat sources comprise flamelessdistributed combustors.
 1611. The method of claim 1605, wherein the oneor more heat sources comprise natural distributed combustors.
 1612. Themethod of claim 1605, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.1613. The method of claim 1605, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 1614. The method of claim 1605,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of the oilshale formation from the one or more heat sources, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day provided to the volume is equal to orless than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1615. The methodof claim 1605, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1616. The method of claim1605, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1617. The method of claim 1605, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1618. The method of claim 1605, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1619.The method of claim 1605, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1620. The method of claim 1605, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1621. The method of claim 1605, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1622. The method of claim 1605,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1623. The method ofclaim 1605, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1624. Themethod of claim 1605, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1625. The method ofclaim 1605, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1626. The method of claim 1605, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1627. The methodof claim 1605, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1628. The method of claim1605, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1629. The method ofclaim 1605, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1630. The method of claim 1605, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1631.The method of claim 1605, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1632. The method of claim 1605, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1633. The method ofclaim 1632, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1634. The method ofclaim 1605, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1635. The method of claim 1605, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1636. The method ofclaim 1605, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1637. The method ofclaim 1605, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1638. The method of claim 1605, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1639. Themethod of claim 1605, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1640. The method of claim 1605, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 1641. The methodof claim 1605, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 1642. The methodof claim 1641, wherein at least about 20 heat sources are disposed inthe formation for each production well.
 1643. The method of claim 1605,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 1644.The method of claim 1605, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1645. A methodof treating an oil shale formation in situ, comprising: providing heatfrom one or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; wherein at least some hydrocarbonswithin the selected section have an initial atomic hydrogen weightpercentage of greater than about 4.0%; and producing a mixture from theformation.
 1646. The method of claim 1645, wherein the one or more heatsources comprise at least two heat sources, and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 1647. Themethod of claim 1645, further comprising maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 1648.The method of claim 1645, wherein the one or more heat sources compriseelectrical heaters.
 1649. The method of claim 1645, wherein the one ormore heat sources comprise surface burners.
 1650. The method of claim1645, wherein the one or more heat sources comprise flamelessdistributed combustors.
 1651. The method of claim 1645, wherein the oneor more heat sources comprise natural distributed combustors.
 1652. Themethod of claim 1645, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.1653. The method of claim 1645, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 1654. The method of claim 1645,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of the oilshale formation from the one or more heat sources, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day provided to the volume is equal to orless than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1655. The methodof claim 1645, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1656. The method of claim1645, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1657. The method of claim 1645, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1658. The method of claim 1645, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1659.The method of claim 1645, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1660. The method of claim 1645, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1661. The method of claim 1645, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1662. The method of claim 1645,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1663. The method ofclaim 1645, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1664. Themethod of claim 1645, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1665. The method ofclaim 1645, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1666. The method of claim 1645, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1667. The methodof claim 1645, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1668. The method of claim1645, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1669. The method ofclaim 1645, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1670. The method of claim 1645, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1671.The method of claim 1645, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1672. The method of claim 1645, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1673. The method ofclaim 1672, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1674. The method ofclaim 1645, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1675. The method of claim 1645, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1676. The method ofclaim 1645, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1677. The method ofclaim 1645, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1678. The method of claim 1645, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1679. Themethod of claim 1645, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1680. The method of claim 1645, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 1681. The methodof claim 1645, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 1682. The methodof claim 1681, wherein at least about 20 heat sources are disposed inthe formation for each production well.
 1683. The method of claim 1645,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 1684.The method of claim 1645, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1685. A methodof treating an oil shale formation in situ, comprising: providing heatfrom one or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; wherein the selected section has beenselected for heating using vitrinite reflectance of at least somehydrocarbons in the selected section, and wherein at least a portion ofthe hydrocarbons in the selected section comprises a vitrinitereflectance of greater than about 0.3%; wherein at least a portion ofthe hydrocarbons in the selected section comprises a vitrinitereflectance of less than about 4.5%; and producing a mixture from theformation.
 1686. The method of claim 1685, wherein the one or more heatsources comprise at least two heat sources, and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 1687. Themethod of claim 1685, further comprising maintaining a temperaturewithin the selected section within a pyrolysis temperature.
 1688. Themethod of claim 1685, wherein the vitrinite reflectance of at least theportion of hydrocarbons within the selected section is between about0.47% and about 1.5% such that a majority of the produced mixturecomprises condensable hydrocarbons.
 1689. The method of claim 1685,wherein the vitrinite reflectance of at least the portion ofhydrocarbons within the selected section is between about 1.4% and about4.2% such that a majority of the produced mixture comprisesnon-condensable hydrocarbons.
 1690. The method of claim 1685, whereinthe one or more heat sources comprise electrical heaters.
 1691. Themethod of claim 1685, wherein the one or more heat sources comprisesurface burners.
 1692. The method of claim 1685, wherein the one or moreheat sources comprise flameless distributed combustors.
 1693. The methodof claim 1685, wherein the one or more heat sources comprise naturaldistributed combustors.
 1694. The method of claim 1685, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1695. The method of claim 1685,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1696. The method of claim 1685, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 1697. The method of claim 1685, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 1698. The method of claim 1685, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 1699. The method of claim1685, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1700. The method of claim1685, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1701. The method of claim 1685,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 1702. The method ofclaim 1685, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1703.The method of claim 1685, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1704. The method of claim 1685, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1705. The method of claim 1685, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1706. The method of claim 1685, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1707. The method of claim 1685, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1708. The method of claim 1685, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1709. The method of claim 1685, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1710. The method of claim 1685, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1711. The method of claim 1685, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1712. The method of claim1685, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1713. The method of claim 1685,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 1714. The method of claim 1685,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 1715. The method of claim 1714, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 1716. The method of claim 1685, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 1717. The method of claim 1685, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 1718. The method of claim 1685, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 1719. The method of claim 1685, furthercomprising: producing hydrogen and condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1720. Themethod of claim 1685, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 1721. The method of claim 1685,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 1722.The method of claim 1685, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 1723. The method of claim 1685, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 1724. The method of claim 1723,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 1725. The method of claim 1685, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 1726. The method of claim 1685,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 1727. A method of treating an oilshale formation in situ, comprising: providing heat from one or moreheat sources to at least a portion of the formation; allowing the heatto transfer from the one or more heat sources to a selected section ofthe formation; wherein the selected section has been selected forheating using a total organic matter weight percentage of at least aportion of the selected section, and wherein at least the portion of theselected section comprises a total organic matter weight percentage, ofat least about 5.0%; and producing a mixture from the formation. 1728.The method of claim 1727, wherein the one or more heat sources compriseat least two heat sources, and wherein superposition of heat from atleast the two heat sources pyrolyzes at least some hydrocarbons withinthe selected section of the formation.
 1729. The method of claim 1727,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 1730. The method of claim 1727,wherein the one or more heat sources comprise electrical heaters. 1731.The method of claim 1727, wherein the one or more heat sources comprisesurface burners.
 1732. The method of claim 1727, wherein the one or moreheat sources comprise flameless distributed combustors.
 1733. The methodof claim 1727, wherein the one or more heat sources comprise naturaldistributed combustors.
 1734. The method of claim 1727, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1735. The method of claim 1727,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1736. The method of claim 1727, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 1737. The method of claim 1727, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 1738. The method of claim 1727, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 1739. The method of claim1727, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1740. The method of claim1727, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1741. The method of claim 1727,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 1742. The method ofclaim 1727, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1743.The method of claim 1727, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1744. The method of claim 1727, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1745. The method of claim 1727, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1746. The method of claim 1727, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1747. The method of claim 1727, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1748. The method of claim 1727, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1749. The method of claim 1727, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1750. The method of claim 1727, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1751. The method of claim 1727, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1752. The method of claim1727, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1753. The method of claim 1727,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 1754. The method of claim 1727,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 1755. The method of claim 1754, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 1756. The method of claim 1727, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 1757. The method of claim 1727, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 1758. The method of claim 1727, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 1759. The method of claim 1727, furthercomprising: producing hydrogen and condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1760. Themethod of claim 1727, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 1761. The method of claim 1727,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 1762.The method of claim 1727, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 1763. The method of claim 1727, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 1764. The method of claim 1763,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 1765. The method of claim 1727, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 1766. The method of claim 1727,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 1767. A method of treating an oilshale formation in situ, comprising: providing heat from one or moreheat sources to at least a portion of the formation; allowing the heatto transfer from the one or more heat sources to a selected section ofthe formation; wherein at least some hydrocarbons within the selectedsection have an initial total organic matter weight percentage of atleast about 5.0%; and producing a mixture from the formation.
 1768. Themethod of claim 1767, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 1769. The method of claim 1767,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 1770. The method of claim 1767,wherein the one or more heat sources comprise electrical heaters. 1771.The method of claim 1767, wherein the one or more heat sources comprisesurface burners.
 1772. The method of claim 1767, wherein the one or moreheat sources comprise flameless distributed combustors.
 1773. The methodof claim 1767, wherein the one or more heat sources comprise naturaldistributed combustors.
 1774. The method of claim 1767, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1775. The method of claim 1767,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1776. The method of claim 1767, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 1777. The method of claim 1767, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 1778. The method of claim 1767, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 1779. The method of claim1767, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1780. The method of claim1767, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1781. The method of claim 1767,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 1782. The method ofclaim 1767, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1783.The method of claim 1767, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1784. The method of claim 1767, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1785. The method of claim 1767, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1786. The method of claim 1767, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1787. The method of claim 1767, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1788. The method of claim 1767, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1789. The method of claim 1767, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1790. The method of claim 1767, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1791. The method of claim 1767, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1792. The method of claim1767, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1793. The method of claim 1767,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 1794. The method of claim 1767,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 1795. The method of claim 1794, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 1796. The method of claim 1767, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 1797. The method of claim 1767, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 1798. The method of claim 1767, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 1799. The method of claim 1767, furthercomprising: producing hydrogen and condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1800. Themethod of claim 1767, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 1801. The method of claim 1767,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 1802.The method of claim 1767, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 1803. The method of claim 1767, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 1804. The method of claim 1803,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 1805. The method of claim 1767, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 1806. The method of claim 1767,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 1807. A method of treating an oilshale formation in situ, comprising: providing heat from one or moreheat sources to at least a portion of the formation; allowing the heatto transfer from the one or more heat sources to a selected section ofthe formation; wherein the selected section has been selected forheating using an atomic oxygen weight percentage of at least a portionof hydrocarbons in the selected section, and wherein at least a portionof the hydrocarbons in the selected section comprises an atomic oxygenweight percentage of less than about 15% when measured on a dry, ashfree basis; and producing a mixture from the formation.
 1808. The methodof claim 1807, wherein the one or more heat sources comprise at leasttwo heat sources, and wherein superposition of heat from at least thetwo heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 1809. The method of claim 1807,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 1810. The method of claim 1807,wherein the one or more heat sources comprise electrical heaters. 1811.The method of claim 1807, wherein the one or more heat sources comprisesurface burners.
 1812. The method of claim 1807, wherein the one or moreheat sources comprise flameless distributed combustors.
 1813. The methodof claim 1807, wherein the one or more heat sources comprise naturaldistributed combustors.
 1814. The method of claim 1807, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1815. The method of claim 1807,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1816. The method of claim 1807, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 1817. The method of claim 1807, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 1818. The method of claim 1807, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 1819. The method of claim1807, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1820. The method of claim1807, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1821. The method of claim 1807,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 1822. The method ofclaim 1807, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1823.The method of claim 1807, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1824. The method of claim 1807, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1825. The method of claim 1807, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1826. The method of claim 1807, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1827. The method of claim 1807, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1828. The method of claim 1807, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1829. The method of claim 1807, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1830. The method of claim 1807, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1831. The method of claim 1807, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1832. The method of claim1807, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1833. The method of claim 1807,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 1834. The method of claim 1807,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 1835. The method of claim 1834, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 1836. The method of claim 1807, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 1837. The method of claim 1807, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 1838. The method of claim 1807, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 1839. The method of claim 1807, furthercomprising: producing hydrogen and condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1840. Themethod of claim 1807, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 1841. The method of claim 1807,wherein allowing the heat to transfer further comprises substantiallyuniformly increasing a permeability of a majority of the selectedsection.
 1842. The method of claim 1807, further comprising controllingthe heat to yield greater than about 60% by weight of condensablehydrocarbons, as measured by Fischer Assay.
 1843. The method of claim1807, wherein producing the mixture comprises producing the mixture in aproduction well, and wherein at least about 7 heat sources are disposedin the formation for each production well.
 1844. The method of claim1843, wherein at least about 20 heat sources are disposed in theformation for each production well.
 1845. The method of claim 1807,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 1846.The method of claim 1807, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1847. A methodof treating an oil shale formation in situ, comprising: providing heatfrom one or more heat sources to a selected section of the formation;allowing the heat to transfer from the one or more heat sources to theselected section of the formation to pyrolyze hydrocarbon within theselected section; wherein at least some hydrocarbons within the selectedsection have an initial atomic oxygen weight percentage of less thanabout 15%; and producing a mixture from the formation.
 1848. The methodof claim 1847, wherein the one or more heat sources comprise at leasttwo heat sources, and wherein superposition of heat from at least thetwo heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 1849. The method of claim 1847,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range
 1850. The method of claim 1847,wherein the one or more heat sources comprise electrical heaters. 1851.The method of claim 1847, wherein the one or more heat sources comprisesurface burners.
 1852. The method of claim 1847, wherein the one or moreheat sources comprise flameless distributed combustors.
 1853. The methodof claim 1847, wherein the one or more heat sources comprise naturaldistributed combustors.
 1854. The method of claim 1847, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1855. The method of claim 1847,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1856. The method of claim 1847, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 1857. The method of claim 1847, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 1858. The method of claim 1847, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 1859. The method of claim1847, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1860. The method of claim1847, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1861. The method of claim 1847,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 1862. The method ofclaim 1847, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1863.The method of claim 1847, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1864. The method of claim 1847, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1865. The method of claim 1847, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1866. The method of claim 1847, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1867. The method of claim 1847, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1868. The method of claim 1847, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1869. The method of claim 1847, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1870. The method of claim 1847, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1871. The method of claim 1847, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1872. The method of claim1847, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1873. The method of claim 1847,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 1874. The method of claim 1847,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 1875. The method of claim 1874, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 1876. The method of claim 1847, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 1877. The method of claim 1847, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 1878. The method of claim 1847, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 1879. The method of claim 1847, furthercomprising: producing hydrogen and condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1880. Themethod of claim 1847, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 1881. The method of claim 1847,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 1882.The method of claim 1847, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 1883. The method of claim 1847, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 1884. The method of claim 1883,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 1885. The method of claim 1847, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 1886. The method of claim 1847,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 1887. A method of treating an oilshale formation in situ, comprising: providing heat from one or moreheat sources to at least a portion of the formation; allowing the heatto transfer from the one or more heat sources to a selected section ofthe formation; wherein the selected section has been selected forheating using an atomic hydrogen to carbon ratio of at least a portionof hydrocarbons in the selected section, wherein at least a portion ofthe hydrocarbons in the selected section comprises an atomic hydrogen tocarbon ratio greater than about 0.70, and wherein the atomic hydrogen tocarbon ratio is less than about 1.65; and producing a mixture from theformation.
 1888. The method of claim 1887, wherein the one or more heatsources comprise at least two heat sources, and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 1889. Themethod of claim 1887, further comprising maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 1890.The method of claim 1887, wherein the one or more heat sources compriseelectrical heaters.
 1891. The method of claim 1887, wherein the one ormore heat sources comprise surface burners.
 1892. The method of claim1887, wherein the one or more heat sources comprise flamelessdistributed combustors.
 1893. The method of claim 1887, wherein the oneor more heat sources comprise natural distributed combustors.
 1894. Themethod of claim 1887, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.1895. The method of claim 1887, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 1896. The method of claim 1887,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of the oilshale formation from the one or more heat sources, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day provided to the volume is equal to orless than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1897. The methodof claim 1887, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1898. The method of claim1887, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1899. The method of claim 1887, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1900. The method of claim 1887, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1901.The method of claim 1887, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1902. The method of claim 1887, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1903. The method of claim 1887, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1904. The method of claim 1887,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1905. The method ofclaim 1887, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1906. Themethod of claim 1887, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1907. The method ofclaim 1887, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1908. The method of claim 1887, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1909. The methodof claim 1887, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1910. The method of claim1887, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1911. The method ofclaim 1887, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1912. The method of claim 1887, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1913.The method of claim 1887, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1914. The method of claim 1887, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1915. The method ofclaim 1914, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1916. The method ofclaim 1887, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1917. The method of claim 1887, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1918. The method ofclaim 1887, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1919. The method ofclaim 1887, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1920. The method of claim 1887, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1921. Themethod of claim 1887, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1922. The method of claim 1887, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 1923. The methodof claim 1887, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 1924. The methodof claim 1923, wherein at least about 20 heat sources are disposed inthe formation for each production well.
 1925. The method of claim 1887,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 1926.The method of claim 1887, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1927. A methodof treating an oil shale formation in situ, comprising: providing heatfrom one or more heat sources to a selected section of the formation;allowing the heat to transfer from the one or more heat sources to theselected section of the formation to pyrolyze hydrocarbons within theselected section; wherein at least some hydrocarbons within the selectedsection have an initial atomic hydrogen to carbon ratio greater thanabout 0.70; wherein the initial atomic hydrogen to carbon ratio is lessthan about 1.65; and producing a mixture from the formation.
 1928. Themethod of claim 1927, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 1929. The method of claim 1927,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 1930. The method of claim 1927,wherein the one or more heat sources comprise electrical heaters. 1931.The method of claim 1927, wherein the one or more heat sources comprisesurface burners.
 1932. The method of claim 1927, wherein the one or moreheat sources comprise flameless distributed combustors.
 1933. The methodof claim 1927, wherein the one or more heat sources comprise naturaldistributed combustors.
 1934. The method of claim 1927, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1935. The method of claim 1927,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1936. The method of claim 1927, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 1937. The method of claim 1927, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 1938. The method of claim 1927, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 1939. The method of claim1927, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1940. The method of claim1927, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1941. The method of claim 1927,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 1942. The method ofclaim 1927, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1943.The method of claim 1927, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1944. The method of claim 1927, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1945. The method of claim 1927, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1946. The method of claim 1927, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1947. The method of claim 1927, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1948. The method of claim 1927, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1949. The method of claim 1927, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1950. The method of claim 1927, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1951. The method of claim 1927, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1952. The method of claim1927, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1953. The method of claim 1927,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 1954. The method of claim 1927,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 1955. The method of claim 1954, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 1956. The method of claim 1927, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 1957. The method of claim 1927, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 1958. The method of claim 1927, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 1959. The method of claim 1927, furthercomprising: producing hydrogen and condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1960. Themethod of claim 1927, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 1961. The method of claim 1927,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 1962.The method of claim 1927, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 1963. The method of claim 1927, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 1964. The method of claim 1963,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 1965. The method of claim 1927, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 1966. The method of claim 1927,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 1967. A method of treating an oilshale formation in situ, comprising: providing heat from one or moreheat sources to at least a portion of the formation; allowing the heatto transfer from the one or more heat sources to a selected section ofthe formation; wherein the selected section has been selected forheating using an atomic oxygen to carbon ratio of at least a portion ofhydrocarbons in the selected section, wherein at least a portion of thehydrocarbons in the selected section comprises an atomic oxygen tocarbon ratio greater than about 0.025, and wherein the atomic oxygen tocarbon ratio of at least a portion of the hydrocarbons in the selectedsection is less than about 0.15; and producing a mixture from theformation.
 1968. The method of claim 1967, wherein the one or more heatsources comprise at least two heat sources, and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 1969. Themethod of claim 1967, further comprising maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 1970.The method of claim 1967, wherein the one or more heat sources compriseelectrical heaters.
 1971. The method of claim 1967, wherein the one ormore heat sources comprise surface burners.
 1972. The method of claim1967, wherein the one or more heat sources comprise flamelessdistributed combustors.
 1973. The method of claim 1967, wherein the oneor more heat sources comprise natural distributed combustors.
 1974. Themethod of claim 1967, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.1975. The method of claim 1967, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 1976. The method of claim 1967,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of the oilshale formation from the one or more heat sources, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day provided to the volume is equal to orless than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1977. The methodof claim 1967, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1978. The method of claim1967, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1979. The method of claim 1967, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1980. The method of claim 1967, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1981.The method of claim 1967, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1982. The method of claim 1967, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1983. The method of claim 1967, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1984. The method of claim 1967,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1985. The method ofclaim 1967, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1986. Themethod of claim 1967, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1987. The method ofclaim 1967, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1988. The method of claim 1967, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1989. The methodof claim 1967, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1990. The method of claim1967, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1991. The method ofclaim 1967, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1992. The method of claim 1967, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1993.The method of claim 1967, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1994. The method of claim 1967, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1995. The method ofclaim 1994, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1996. The method ofclaim 1967, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1997. The method of claim 1967, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1998. The method ofclaim 1967, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1999. The method ofclaim 1967, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2000. The method of claim 1967, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 2001. Themethod of claim 1967, wherein allowing the heat to transfer furthercomprises substantially uniformly increasing a permeability of amajority of the selected section.
 2002. The method of claim 1967,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by Fischer Assay.2003. The method of claim 1967, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well.2004. The method of claim 2003, wherein at least about 20 heat sourcesare disposed in the formation for each production well.
 2005. The methodof claim 1967, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,and wherein the unit of heat sources comprises a triangular pattern.2006. The method of claim 1967, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, wherein the unit of heat sources comprises atriangular pattern, and wherein a plurality of the units are repeatedover an area of the formation to form a repetitive pattern of units.2007. A method of treating an oil shale formation in situ, comprisingproviding heat from one or more heat sources to a selected section ofthe formation; allowing the heat to transfer from the one or more heatsources to the selected section of the formation to pyrolyzehydrocarbons within the selected section; wherein at least somehydrocarbons within the selected section have an initial atomic oxygento carbon ratio greater than about 0.025; wherein the initial atomicoxygen to carbon ratio is less than about 0.15; and producing a mixturefrom the formation.
 2008. The method of claim 2007, wherein the one ormore heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.2009. The method of claim 2007, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 2010. The method of claim 2007, wherein the one or more heatsources comprise electrical heaters.
 2011. The method of claim 2007,wherein the one or more heat sources comprise surface burners.
 2012. Themethod of claim 2007, wherein the one or more heat sources compriseflameless distributed combustors.
 2013. The method of claim 2007,wherein the one or more heat sources comprise natural distributedcombustors.
 2014. The method of claim 2007, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2015. The method of claim 2007,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2016. The method of claim 2007, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 2017. The method of claim 2007, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 2018. The method of claim 2007, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 2019. The method of claim2007, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 2020. The method of claim2007, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 2021. The method of claim 2007,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 2022. The method ofclaim 2007, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2023.The method of claim 2007, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2024. The method of claim 2007, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 2025. The method of claim 2007, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2026. The method of claim 2007, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 2027. The method of claim 2007, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 2028. The method of claim 2007, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 2029. The method of claim 2007, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 2030. The method of claim 2007, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2031. The method of claim 2007, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 2032. The method of claim2007, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 2033. The method of claim 2007,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 2034. The method of claim 2007,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 2035. The method of claim 2034, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2036. The method of claim 2007, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2037. The method of claim 2007, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2038. The method of claim 2007, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 2039. The method of claim 2007, furthercomprising: producing hydrogen and condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 2040. Themethod of claim 2007, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 2041. The method of claim 2007,wherein allowing the heat to transfer further comprises substantiallyuniformly increasing a permeability of a majority of the selectedsection.
 2042. The method of claim 2007, further comprising controllingthe heat to yield greater than about 60% by weight of condensablehydrocarbons, as measured by Fischer Assay.
 2043. The method of claim2007, wherein producing the mixture comprises producing the mixture in aproduction well, and wherein at least about 7 heat sources are disposedin the formation for each production well.
 2044. The method of claim2043, wherein at least about 20 heat sources are disposed in theformation for each production well.
 2045. The method of claim 2007,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 2046.The method of claim 2007, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 2047. A methodof treating an oil shale formation in situ, comprising: providing heatfrom one or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; wherein the selected section has beenselected for heating using a moisture content in the selected section,and wherein at least a portion of the selected section comprises amoisture content of less than about 15% by weight; and producing amixture from the formation.
 2048. The method of claim 2047, wherein theone or more heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.2049. The method of claim 2047, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 2050. The method of claim 2047, wherein the one or more heatsources comprise electrical heaters.
 2051. The method of claim 2047,wherein the one or more heat sources comprise surface burners.
 2052. Themethod of claim 2047, wherein the one or more heat sources compriseflameless distributed combustors.
 2053. The method of claim 2047,wherein the one or more heat sources comprise natural distributedcombustors.
 2054. The method of claim 2047, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2055. The method of claim 2047,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2056. The method of claim 2047, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 2057. The method of claim 2047, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 2058. The method of claim 2047, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 2059. The method of claim2047, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 2060. The method of claim2047, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 2061. The method of claim 2047,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 2062. The method ofclaim 2047, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2063.The method of claim 2047, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2064. The method of claim 2047, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 2065. The method of claim 2047, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2066. The method of claim 2047, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 2067. The method of claim 2047, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 2068. The method of claim 2047, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 2069. The method of claim 2047, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 2070. The method of claim 2047, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2071. The method of claim 2047, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 2072. The method of claim2047, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 2073. The method of claim 2047,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 2074. The method of claim 2047,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 2075. The method of claim 2074, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2076. The method of claim 2047, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2077. The method of claim 2047, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2078. The method of claim 2047, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 2079. The method of claim 2047, furthercomprising: producing hydrogen and condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 2080. Themethod of claim 2047, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 2081. The method of claim 2047,wherein allowing the heat to transfer further comprises substantiallyuniformly increasing a permeability of a majority of the selectedsection.
 2082. The method of claim 2047, further comprising controllingthe heat to yield greater than about 60% by weight of condensablehydrocarbons, as measured by Fischer Assay.
 2083. The method of claim2047, wherein producing the mixture comprises producing the mixture in aproduction well, and wherein at least about 7 heat sources are disposedin the formation for each production well.
 2084. The method of claim2083, wherein at least about 20 heat sources are disposed in theformation for each production well.
 2085. The method of claim 2047,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 2086.The method of claim 2047, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 2087. A methodof treating an oil shale formation in situ, comprising: providing heatfrom one or more heat sources to a selected section of the formation;allowing the heat to transfer from the one or more heat sources to theselected section of the formation; wherein at least a portion of theselected section has an initial moisture content of less than about 15%by weight; and producing a mixture from the formation.
 2088. The methodof claim 2087, wherein the one or more heat sources comprise at leasttwo heat sources, and wherein superposition of heat from at least thetwo heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 2089. The method of claim 2087,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 2090. The method of claim 2087,wherein the one or more heat sources comprise electrical heaters. 2091.The method of claim 2087, wherein the one or more heat sources comprisesurface burners.
 2092. The method of claim 2087, wherein the one or moreheat sources comprise flameless distributed combustors.
 2093. The methodof claim 2087, wherein the one or more heat sources comprise naturaldistributed combustors.
 2094. The method of claim 2087, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2095. The method of claim 2087,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2096. The method of claim 2087, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 2097. The method of claim 2087, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 2098. The method of claim 2087, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 2099. The method of claim2087, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 2100. The method of claim2087, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 2101. The method of claim 2087,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 2102. The method ofclaim 2087, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2103.The method of claim 2087, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2104. The method of claim 2087, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 2105. The method of claim 2087, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2106. The method of claim 2087, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 2107. The method of claim 2087, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 2108. The method of claim 2087, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 2109. The method of claim 2087, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 2110. The method of claim 2087, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2111. The method of claim 2087, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 2112. The method of claim2087, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 2113. The method of claim 2087,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 2114. The method of claim 2087,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 2115. The method of claim 2114, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2116. The method of claim 2087, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2117. The method of claim 2087, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2118. The method of claim 2087, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 2119. The method of claim 2087, furthercomprising: producing hydrogen and condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 2120. Themethod of claim 2087, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 2121. The method of claim 2087,wherein allowing the heat to transfer further comprises substantiallyuniformly increasing a permeability of a majority of the selectedsection.
 2122. The method of claim 2087, further comprising controllingthe heat to yield greater than about 60% by weight of condensablehydrocarbons, as measured by Fischer Assay.
 2123. The method of claim2087, wherein producing the mixture comprises producing the mixture in aproduction well, and wherein at least about 7 heat sources are disposedin the formation for each production well.
 2124. The method of claim2124, wherein at least about 20 heat sources are disposed in theformation for each production well.
 2125. The method of claim 2087,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 2126.The method of claim 2087, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 2127. A methodof treating an oil shale formation in situ, comprising: providing heatfrom one or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; wherein the selected section isheated in a reducing environment during at least a portion of the timethat the selected section is being heated; and producing a mixture fromthe formation.
 2128. The method of claim 2127, wherein the one or moreheat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.2129. The method of claim 2127, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 2130. The method of claim 2127, wherein the one or more heatsources comprise electrical heaters.
 2131. The method of claim 2127,wherein the one or more heat sources comprise surface burners.
 2132. Themethod of claim 2127, wherein the one or more heat sources compriseflameless distributed combustors.
 2133. The method of claim 2127,wherein the one or more heat sources comprise natural distributedcombustors.
 2134. The method of claim 2127, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2135. The method of claim 2127,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2136. The method of claim 2127, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 2137. The method of claim 2127, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 2138. The method of claim 2127, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 2139. The method of claim2127, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 2140. The method of claim2127, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 2141. The method of claim 2127,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 2142. The method ofclaim 2127, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2143.The method of claim 2127, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2144. The method of claim 2127, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 2145. The method of claim 2127, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2146. The method of claim 2127, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 2147. The method of claim 2127, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 2148. The method of claim 2127, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 2149. The method of claim 2127, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 2150. The method of claim 2127, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2151. The method of claim 2127, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 2152. The method of claim2127, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 2153. The method of claim 2127,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 2154. The method of claim 2127,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 2155. The method of claim 2154, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2156. The method of claim 2127, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2157. The method of claim 2127, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2158. The method of claim 2127, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 2159. The method of claim 2127, furthercomprising: producing hydrogen and condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 2160. Themethod of claim 2127, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 2161. The method of claim 2127,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 2162.The method of claim 2127, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 2163. The method of claim 2127, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 2164. The method of claim 2163,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 2165. The method of claim 2127, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 2166. The method of claim 2127,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 2167. A method of treating an oilshale formation in situ, comprising: heating a first section of theformation to produce a mixture from the formation; heating a secondsection of the formation; and recirculating a portion of the producedmixture from the first section into the second section of the formationto provide a reducing environment within the second section of theformation.
 2168. The method of claim 2167, further comprisingmaintaining a temperature within the first section or the second sectionwithin a pyrolysis temperature range.
 2169. The method of claim 2167,wherein heating the first or the second section comprises heating withan electrical heater.
 2170. The method of claim 2167, wherein heatingthe first or the second section comprises heating with a surface burner.2171. The method of claim 2167, wherein heating the first or the secondsection comprises heating with a flameless distributed combustor. 2172.The method of claim 2167, wherein heating the first or the secondsection comprises heating with a natural distributed combustor. 2173.The method of claim 2167, further comprising controlling a pressure anda temperature within at least a majority of the first or second sectionof the formation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.2174. The method of claim 2167, further comprising controlling the heatsuch that an average heating rate of the first or the second section isless than about 1° C. per day during pyrolysis.
 2175. The method ofclaim 2167, wherein heating the first or the second section comprises:heating a selected volume (V) of the oil shale formation from one ormore heat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 2176. The method of claim 2167, wherein heatingthe first or the second section comprises transferring heatsubstantially by conduction.
 2177. The method of claim 2167, whereinheating the first or the second section comprises heating the first orthe second section such that a thermal conductivity of at least aportion of the first or the second section is greater than about 0.5W/(m ° C.).
 2178. The method of claim 2167, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 2179. The method of claim 2167, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 2180.The method of claim 2167, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 2181. The method of claim 2167, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 2182. The method of claim 2167, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2183. The method of claim 2167,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 2184. The method ofclaim 2167, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2185. Themethod of claim 2167, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2186. The method ofclaim 2167, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2187. The method of claim 2167, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2188. The methodof claim 2167, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2189. The method of claim2167, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 2190. The method ofclaim 2167, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.2191. The method of claim 2167, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 2192.The method of claim 2167, further comprising controlling a pressurewithin at least a majority of the first or second section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 2193. The method of claim 2167, further comprising controllingformation conditions to produce the mixture, wherein a partial pressureof H₂ within the mixture is greater than about 0.5 bars.
 2194. Themethod of claim 2193, wherein the partial pressure of H₂ within themixture is measured when the mixture is at a production well.
 2195. Themethod of claim 2167, further comprising altering a pressure within theformation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than about
 25. 2196. The method of claim2167, further comprising: providing hydrogen (H₂) to the first or secondsection to hydrogenate hydrocarbons within the first or second section;and heating a portion of the first or second section with heat fromhydrogenation.
 2197. The method of claim 2167, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2198. The method of claim2167, wherein heating the first or the second section comprisesincreasing a permeability of a majority of the first or the secondsection to greater than about 100 millidarcy.
 2199. The method of claim2167, wherein heating the first or the second section comprisessubstantially uniformly increasing a permeability of a majority of thefirst or the second section.
 2200. The method of claim 2167, furthercomprising controlling the heat to yield greater than about 60% byweight of condensable hydrocarbons, as measured by Fischer Assay. 2201.The method of claim 2167, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well.2202. The method of claim 2201, wherein at least about 20 heat sourcesare disposed in the formation for each production well.
 2203. The methodof claim 2167, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,and wherein the unit of heat sources comprises a triangular pattern.2204. The method of claim 2167, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, wherein the unit of heat sources comprises atriangular pattern, and wherein a plurality of the units are repeatedover an area of the formation to form a repetitive pattern of units.2205. A method of treating an oil shale formation in situ, comprising:providing heat from one or more heat sources to at least a portion ofthe formation; and allowing the heat to transfer from the one or moreheat sources to a selected section of the formation such that apermeability of at least a portion of the selected section increases togreater than about 100 millidarcy.
 2206. The method of claim 2205,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 2207. The method of claim 2205, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 2208. The method of claim 2205, wherein the one ormore heat sources comprise electrical heaters.
 2209. The method of claim2205, wherein the one or more heat sources comprise surface burners.2210. The method of claim 2205, wherein the one or more heat sourcescomprise flameless distributed combustors.
 2211. The method of claim2205, wherein the one or more heat sources comprise natural distributedcombustors.
 2212. The method of claim 2205, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2213. The method of claim 2205,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2214. The method of claim 2205, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 2215. The method of claim 2205, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 2216. The method of claim 2205, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 2217. The method of claim2205, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 2218. The method of claim 2205, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 0.1% byweight to about 15% by weight of the condensable hydrocarbons areolefins.
 2219. The method of claim 2205, further comprising producing amixture from the formation, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 2220. The method of claim 2205, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 2221. The method of claim 2205, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2222. The method of claim 2205, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons issulfur.
 2223. The method of claim 2205, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.2224. The method of claim 2205, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2225. The method ofclaim 2205, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2226. Themethod of claim 2205, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2227. The method of claim2205, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2228. The method of claim 2205, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2229. The method of claim 2205, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2230. The method of claim2205, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2231. The method of claim 2205, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 2232. The method of claim 2205, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bars.
 2233. The method of claim 2232, furthercomprising producing a mixture from the formation, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2234. The method of claim 2205, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2235. The method of claim 2205, further comprising producing amixture from the formation and controlling formation conditions byrecirculating a portion of hydrogen from the mixture into the formation.2236. The method of claim 2205, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 2237. The method of claim 2205, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2238. The method of claim2205, further comprising increasing a permeability of a majority of theselected section to greater than about 5 Darcy.
 2239. The method ofclaim 2205, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 2240. The method of claim 2205, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 2241. The methodof claim 2205, further comprising producing a mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 2242. The method of claim 2241,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 2243. The method of claim 2205, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 2244. The method of claim 2205,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 2245. A method of treating an oilshale formation in situ, comprising: providing heat from one or moreheat sources to at least a portion of the formation; and allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation such that a permeability of a majority of at least aportion of the selected section increases substantially uniformly. 2246.The method of claim 2245, wherein the one or more heat sources compriseat least two heat sources, and wherein superposition of heat from atleast the two heat sources pyrolyzes at least some hydrocarbons withinthe selected section of the formation.
 2247. The method of claim 2245,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 2248. The method of claim 2245,wherein the one or more heat sources comprise electrical heaters. 2249.The method of claim 2245, wherein the one or more heat sources comprisesurface burners.
 2250. The method of claim 2245, wherein the one or moreheat sources comprise flameless distributed combustors.
 2251. The methodof claim 2245, wherein the one or more heat sources comprise naturaldistributed combustors.
 2252. The method of claim 2245, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2253. The method of claim 2245,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2254. The method of claim 2245, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 2255. The method of claim 2245, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 2256. The method of claim 2245, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 2257. The method of claim2245, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 2258. The method of claim 2245, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 0.1% byweight to about 15% by weight of the condensable hydrocarbons areolefins.
 2259. The method of claim 2245, further comprising producing amixture from the formation, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 2260. The method of claim 2245, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 2261. The method of claim 2245, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2262. The method of claim 2245, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons issulfur.
 2263. The method of claim 2245, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.2264. The method of claim 2245, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2265. The method ofclaim 2245, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2266. Themethod of claim 2245, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2267. The method of claim2245, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2268. The method of claim 2245, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2269. The method of claim 2245, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2270. The method of claim2245, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2271. The method of claim 2245, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 2272. The method of claim 2245, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bars.
 2273. The method of claim 2245, furthercomprising producing a mixture from the formation, wherein a partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2274. The method of claim 2245, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2275. The method of claim 2245, further comprising producing amixture from the formation and controlling formation conditions byrecirculating a portion of hydrogen from the mixture into the formation.2276. The method of claim 2245, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 2277. The method of claim 2245, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2278. The method of claim2245, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 2279. The method of claim 2245, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 2280. The methodof claim 2245, further comprising producing a mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 2281. The method of claim 2280,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 2282. The method of claim 2245, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 2283. The method of claim 2245,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 2284. A method of treating an oilshale formation in situ, comprising: providing heat from one or moreheat sources to at least a portion of the formation; and allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation such that a porosity of a majority of at least aportion of the selected section increases substantially uniformly. 2285.The method of claim 2284, wherein the one or more heat sources compriseat least two heat sources, and wherein superposition of heat from atleast the two heat sources pyrolyzes at least some hydrocarbons withinthe selected section of the formation.
 2286. The method of claim 2284,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 2287. The method of claim 2284,wherein the one or more heat sources comprise electrical heaters. 2288.The method of claim 2284, wherein the one or more heat sources comprisesurface burners.
 2289. The method of claim 2284, wherein the one or moreheat sources comprise flameless distributed combustors.
 2290. The methodof claim 2284, wherein the one or more heat sources comprise naturaldistributed combustors.
 2291. The method of claim 2284, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2292. The method of claim 2284,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2293. The method of claim 2284, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 2294. The method of claim 2284, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 2295. The method of claim 2284, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 2296. The method of claim2284, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 2297. The method of claim 2284, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 0.1% byweight to about 15% by weight of the condensable hydrocarbons areolefins.
 2298. The method of claim 2284, further comprising producing amixture from the formation, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 2299. The method of claim 2284, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 2300. The method of claim 2284, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2301. The method of claim 2284, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons issulfur.
 2302. The method of claim 2284, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.2303. The method of claim 2284, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2304. The method ofclaim 2284, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2305. Themethod of claim 2284, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2306. The method of claim2284, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2307. The method of claim 2284, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2308. The method of claim 2284, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2309. The method of claim2284, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2310. The method of claim 2284, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 2311. The method of claim 2284, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bars.
 2312. The method of claim 2284, furthercomprising producing a mixture from the formation, wherein a partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2313. The method of claim 2284, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2314. The method of claim 2284, further comprising producing amixture from the formation and controlling formation conditions byrecirculating a portion of hydrogen from the mixture into the formation.2315. The method of claim 2284, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 2316. The method of claim 2284, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2317. The method of claim2284, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 2318. The method of claim 2284, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 2319. The method ofclaim 2284, further comprising controlling the heat to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured byFischer Assay.
 2320. The method of claim 2284, further comprisingproducing a mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well.2321. The method of claim 2320, wherein at least about 20 heat sourcesare disposed in the formation for each production well.
 2322. The methodof claim 2284, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,and wherein the unit of heat sources comprises a triangular pattern.2323. The method of claim 2284, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, wherein the unit of heat sources comprises atriangular pattern, and wherein a plurality of the units are repeatedover an area of the formation to form a repetitive pattern of units.2324. A method of treating an oil shale formation in situ, comprising:providing heat from one or more heat sources to at least a portion ofthe formation; allowing the heat to transfer from the one or more heatsources to a selected section of the formation; and controlling the heatto yield at least about 15% by weight of a total organic carbon contentof at least some of the oil shale formation into condensablehydrocarbons.
 2325. The method of claim 2324, wherein the one or moreheat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.2326. The method of claim 2324, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 2327. The method of claim 2324, wherein the one or more heatsources comprise electrical heaters.
 2328. The method of claim 2324,wherein the one or more heat sources comprise surface burners.
 2329. Themethod of claim 2324, wherein the one or more heat sources compriseflameless distributed combustors.
 2330. The method of claim 2324,wherein the one or more heat sources comprise natural distributedcombustors.
 2331. The method of claim 2324, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2332. The method of claim 2324,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2333. The method of claim 2324, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 2334. The method of claim 2324, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 2335. The method of claim 2324, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 2336. The method of claim2324, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 2337. The method of claim 2324, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 0.1% byweight to about 15% by weight of the condensable hydrocarbons areolefins.
 2338. The method of claim 2324, further comprising producing amixture from the formation, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 2339. The method of claim 2324, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 2340. The method of claim 2324, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2341. The method of claim 2324, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons issulfur.
 2342. The method of claim 2324, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.2343. The method of claim 2324, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2344. The method ofclaim 2324, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2345. Themethod of claim 2324, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2346. The method of claim2324, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2347. The method of claim 2324, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2348. The method of claim 2324, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2349. The method of claim2324, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2350. The method of claim 2324, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 2351. The method of claim 2324, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bars.
 2352. The method of claim 2324, furthercomprising producing a mixture from the formation, wherein a partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2353. The method of claim 2324, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2354. The method of claim 2324, further comprising producing amixture from the formation and controlling formation conditions byrecirculating a portion of hydrogen from the mixture into the formation.2355. The method of claim 2324, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 2356. The method of claim 2324, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2357. The method of claim2324, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 2358. The method of claim 2324, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 2359. The method ofclaim 2324, wherein the heating is controlled to yield greater thanabout 60% by weight of condensable hydrocarbons, as measured by FischerAssay.
 2360. The method of claim 2324, further comprising producing amixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 2361. The methodof claim 2360, wherein at least about 20 heat sources are disposed inthe formation for each production well.
 2362. The method of claim 2324,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 2363.The method of claim 2324, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 2364. A methodof treating an oil shale formation in situ, comprising: providing heatfrom one or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; and controlling the heat to yieldgreater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 2365. The method of claim 2364, wherein theone or more heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.2366. The method of claim 2364, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 2367. The method of claim 2364, wherein the one or more heatsources comprise electrical heaters.
 2368. The method of claim 2364,wherein the one or more heat sources comprise surface burners.
 2369. Themethod of claim 2364, wherein the one or more heat sources compriseflameless distributed combustors.
 2370. The method of claim 2364,wherein the one or more heat sources comprise natural distributedcombustors.
 2371. The method of claim 2364, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2372. The method of claim 2364,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2373. The method of claim 2364, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 2374. The method of claim 2364, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 2375. The method of claim 2364, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 2376. The method of claim2364, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 2377. The method of claim 2364, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 0.1% byweight to about 15% by weight of the condensable hydrocarbons areolefins.
 2378. The method of claim 2364, further comprising producing amixture from the formation, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 2379. The method of claim 2364, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 2380. The method of claim 2364, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2381. The method of claim 2364, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons issulfur.
 2382. The method of claim 2364, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.2383. The method of claim 2364, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2384. The method ofclaim 2364, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2385. Themethod of claim 2364, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2386. The method of claim2364, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2387. The method of claim 2364, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2388. The method of claim 2364, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2389. The method of claim2364, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2390. The method of claim 2364, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 2391. The method of claim 2364, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bars.
 2392. The method of claim 2364, furthercomprising producing a mixture from the formation, wherein a partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2393. The method of claim 2364, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2394. The method of claim 2364, further comprising producing amixture from the formation and controlling formation conditions byrecirculating a portion of hydrogen from the mixture into the formation.2395. The method of claim 2364, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 2396. The method of claim 2364, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2397. The method of claim2364, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 2398. The method of claim 2364, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 2399. The method ofclaim 2364, further comprising producing a mixture in a production well,and wherein at least about 7 heat sources are disposed in the formationfor each production well.
 2400. The method of claim 2399, wherein atleast about 20 heat sources are disposed in the formation for eachproduction well.
 2401. The method of claim 2364, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 2402. The method of claim 2364,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 2403. A method of treating an oilshale formation in situ, comprising: heating a first section of theformation to pyrolyze at least some hydrocarbons in the first sectionand produce a first mixture from the formation; heating a second sectionof the formation to pyrolyze at least some hydrocarbons in the secondsection and produce a second mixture from the formation; and leaving anunpyrolyzed section between the first section and the second section toinhibit subsidence of the formation.
 2404. The method of claim 2403,further comprising maintaining a temperature within the first section orthe second section within a pyrolysis temperature range.
 2405. Themethod of claim 2403, wherein heating the first section or heating thesecond section comprises heating with an electrical heater.
 2406. Themethod of claim 2403, wherein heating the first section or heating thesecond section comprises heating with a surface burner.
 2407. The methodof claim 2403, wherein heating the first section or heating the secondsection comprises heating with a flameless distributed combustor. 2408.The method of claim 2403, wherein heating the first section or heatingthe second section comprises heating with a natural distributedcombustor.
 2409. The method of claim 2403, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe first or second section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2410. The method of claim 2403,further comprising controlling the heat such that an average heatingrate of the first or second section is less than about 1° C. per dayduring pyrolysis.
 2411. The method of claim 2403, wherein heating thefirst section or heating the second section comprises: heating aselected volume (V) of the oil shale formation from one or more heatsources, wherein the formation has an average heat capacity (C_(v)), andwherein the heating pyrolyzes at least some hydrocarbons within theselected volume of the formation; and wherein heating energy/dayprovided to the volume is equal to or less than Pwr, wherein Pwr iscalculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is theheating energy/day, h is an average heating rate of the formation, ρ_(B)is formation bulk density, and wherein the heating rate is less thanabout 10° C./day.
 2412. The method of claim 2403, wherein heating thefirst section or heating the second section comprises transferring heatsubstantially by conduction.
 2413. The method of claim 2403, whereinheating the first section or heating the second section comprisesheating the formation such that a thermal conductivity of at least aportion of the first or second section, respectively, is greater thanabout 0.5 W/(m ° C.).
 2414. The method of claim 2403, wherein the firstor second mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 2415. The method of claim 2403, whereinthe first or second mixture comprises condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 2416. The method of claim 2403, wherein thefirst or second mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 2417. The method ofclaim 2403, wherein the first or second mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2418.The method of claim 2403, wherein the first or second mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2419. The method of claim 2403, wherein the first or secondmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 2420. The method of claim 2403, wherein thefirst or second mixture comprises condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 2421. The method of claim2403, wherein the first or second mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2422. The method ofclaim 2403, wherein the first or second mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2423. The method of claim 2403, wherein the first or secondmixture comprises condensable hydrocarbons, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 2424.The method of claim 2403, wherein the first or second mixture comprisescondensable hydrocarbons, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 2425. Themethod of claim 2403, wherein the first or second mixture comprises anon-condensable component, and wherein the non-condensable componentcomprises hydrogen, and wherein the hydrogen is greater than about 10%by volume of the non-condensable component and wherein the hydrogen isless than about 80% by volume of the non-condensable component. 2426.The method of claim 2403, wherein the first or second mixture comprisesammonia, and wherein greater than about 0.05% by weight of the first orsecond mixture is ammonia.
 2427. The method of claim 2403, wherein thefirst or second mixture comprises ammonia, and wherein the ammonia isused to produce fertilizer.
 2428. The method of claim 2403, furthercomprising controlling a pressure within at least a majority of thefirst or second section of the formation, wherein the controlledpressure is at least about 2.0 bars absolute.
 2429. The method of claim2403, further comprising controlling formation conditions to produce thefirst or second mixture, wherein a partial pressure of H₂ within thefirst or second mixture is greater than about 0.5 bars.
 2430. The methodof claim 2403, wherein a partial pressure of H₂ within the first orsecond mixture is measured when the first or second mixture is at aproduction well.
 2431. The method of claim 2403, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2432. The method of claim 2403, further comprising controllingformation conditions by recirculating a portion of hydrogen from thefirst or second mixture into the formation.
 2433. The method of claim2403, further comprising: providing hydrogen (H₂) to the first or secondsection to hydrogenate hydrocarbons within the first or second section,respectively; and heating a portion of the first or second section,respectively, with heat from hydrogenation.
 2434. The method of claim2403, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2435. The method of claim 2403, wherein heating thefirst section or heating the second section comprises increasing apermeability of a majority of the first or second section, respectively,to greater than about 100 millidarcy.
 2436. The method of claim 2403,wherein heating the first section or heating the second sectioncomprises substantially uniformly increasing a permeability of amajority of the first or second section, respectively.
 2437. The methodof claim 2403, further comprising controlling heating of the first orsecond section to yield greater than about 60% by weight of condensablehydrocarbons, as measured by Fischer Assay, from the first or secondsection, respectively.
 2438. The method of claim 2403, wherein producingthe first or second mixture comprises producing the first or secondmixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 2439. The methodof claim 2438, wherein at least about 20 heat sources are disposed inthe formation for each production well.
 2440. The method of claim 2403,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 2441.The method of claim 2403, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 2442. A methodof treating an oil shale formation in situ, comprising: providing heatfrom one or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; and producing a mixture from theformation through one or more production wells, wherein the heating iscontrolled such that the mixture can be produced from the formation as avapor, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 2443. The method of claim 2442,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 2444. The method of claim 2442, wherein the one ormore heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.2445. The method of claim 2442, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 2446. The method of claim 2442, wherein the one or more heatsources comprise electrical heaters.
 2447. The method of claim 2442,wherein the one or more heat sources comprise surface burners.
 2448. Themethod of claim 2442, wherein the one or more heat sources compriseflameless distributed combustors.
 2449. The method of claim 2442,wherein the one or more heat sources comprise natural distributedcombustors.
 2450. The method of claim 2442, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2451. The method of claim 2442,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2452. The method of claim 2442, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 2453. The method of claim 2442, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 2454. The method of claim 2442, wherein providing heatfrom the one or more heat sources comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 2455. The method of claim2442, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 2456. The method of claim2442, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 2457. The method of claim 2442,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 2458. The method ofclaim 2442, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2459.The method of claim 2442, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2460. The method of claim 2442, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 2461. The method of claim 2442, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2462. The method of claim 2442, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 2463. The method of claim 2442, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 2464. The method of claim 2442, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 2465. The method of claim 2442, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 2466. The method of claim 2442, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2467. The method of claim 2442, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 2468. The method of claim2442, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 2469. The method of claim 2442,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 2470. The method of claim 2442,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 2471. The method of claim 2470, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2472. The method of claim 2442, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2473. The method of claim 2442, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2474. The method of claim 2442, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 2475. The method of claim 2442, furthercomprising: producing hydrogen and condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 2476. Themethod of claim 2442, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 2477. The method of claim 2442,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 2478.The method of claim 2442, wherein the heating is controlled to yieldgreater than about 60% by weight of condensable hydrocarbons, asmeasured by Fischer Assay.
 2479. The method of claim 2442, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, and wherein the unitof heat sources comprises a triangular pattern.
 2480. The method ofclaim 2442, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,wherein the unit of heat sources comprises a triangular pattern, andwherein a plurality of the units are repeated over an area of theformation to form a repetitive pattern of units.
 2481. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least a portion of the formation, whereinthe one or more heat sources are disposed within one or more firstwells; allowing the heat to transfer from the one or more heat sourcesto a selected section of the formation; and producing a mixture from theformation through one or more second wells, wherein one or more of thefirst or second wells are initially used for a first purpose and arethen used for one or more other purposes.
 2482. The method of claim2481, wherein the first purpose comprises removing water from theformation, and wherein the second purpose comprises providing heat tothe formation.
 2483. The method of claim 2481, wherein the first purposecomprises removing water from the formation, and wherein the secondpurpose comprises producing the mixture.
 2484. The method of claim 2481,wherein the first purpose comprises heating, and wherein the secondpurpose comprises removing water from the formation.
 2485. The method ofclaim 2481, wherein the first purpose comprises producing the mixture,and wherein the second purpose comprises removing water from theformation.
 2486. The method of claim 2481, wherein the one or more heatsources comprise electrical heaters.
 2487. The method of claim 2481,wherein the one or more heat sources comprise surface burners.
 2488. Themethod of claim 2481, wherein the one or more heat sources compriseflameless distributed combustors.
 2489. The method of claim 2481,wherein the one or more heat sources comprise natural distributedcombustors.
 2490. The method of claim 2481, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2491. The method of claim 2481,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1.0° C. per day duringpyrolysis.
 2492. The method of claim 2481, wherein providing heat fromthe one or more heat sources to at least the portion of the formationcomprises: heating a selected volume (V) of the oil shale formation fromthe one or more heat sources, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 2493. The method of claim 2481, whereinproviding heat from the one or more heat sources comprises heating theselected section such that a thermal conductivity of at least a portionof the selected section is greater than about 0.5 W/(m ° C.).
 2494. Themethod of claim 2481, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 2495. Themethod of claim 2481, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 2496. The method of claim2481, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.2497. The method of claim 2481, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 2498. The method of claim 2481, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 2499. The method of claim 2481, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 2500. The method of claim 2481,wherein the produced mixture comprises condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 2501. The method of claim2481, wherein the produced mixture comprises condensable hydrocarbons,and wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 2502. The method of claim 2481,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2503. Themethod of claim 2481, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2504. The method of claim2481, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2505. The method of claim 2481, whereinthe produced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2506. The method of claim 2481, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 2507. The method of claim2481, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 2508. The method of claim 2481,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 2509. The method of claim 2481,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 2510. The method ofclaim 2509, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 2511. The method of claim 2481, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 2512. The method of claim 2481, furthercomprising controlling formation conditions, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 2513. The method of claim 2481, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 2514. The method of claim 2481, whereinthe produced mixture comprises hydrogen and condensable hydrocarbons,the method further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 2515. The method of claim 2481, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 2516. The methodof claim 2481, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 2517. The method of claim 2481, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 2518. The methodof claim 2481, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 2519. The methodof claim 2518, wherein at least about 20 heat sources are disposed inthe formation for each production well.
 2520. The method of claim 2481,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 2521.The method of claim 2481, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 2522. A methodfor forming heater wells in an oil shale formation, comprising: forminga first wellbore in the formation; forming a second wellbore in theformation using magnetic tracking such that the second wellbore isarranged substantially parallel to the first wellbore; and providing atleast one heat source within the first wellbore and at least one heatsource within the second wellbore such that the heat sources can provideheat to at least a portion of the formation.
 2523. The method of claim2522, wherein superposition of heat from the at least one heat sourcewithin the first wellbore and the at least one heat source within thesecond wellbore pyrolyzes at least some hydrocarbons within a selectedsection of the formation.
 2524. The method of claim 2522, furthercomprising maintaining a temperature within a selected section within apyrolysis temperature range.
 2525. The method of claim 2522, wherein theheat sources comprise electrical heaters.
 2526. The method of claim2522, wherein the heat sources comprise surface burners.
 2527. Themethod of claim 2522, wherein the heat sources comprise flamelessdistributed combustors.
 2528. The method of claim 2522, wherein the heatsources comprise natural distributed combustors.
 2529. The method ofclaim 2522, further comprising controlling a pressure and a temperaturewithin at least a majority of a selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 2530. The method ofclaim 2522, further comprising controlling the heat from the heatsources such that heat transferred from the heat sources to at least theportion of the hydrocarbons is less than about 1° C. per day duringpyrolysis.
 2531. The method of claim 2522, further comprising: heating aselected volume (V) of the oil shale formation from the heat sources,wherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./day.2532. The method of claim 2522, further comprising allowing the heat totransfer from the heat sources to at least the portion of the formationsubstantially by conduction.
 2533. The method of claim 2522, furthercomprising providing heat from the heat sources to at least the portionof the formation such that a thermal conductivity of at least theportion of the formation is greater than about 0.5 W/(m ° C.).
 2534. Themethod of claim 2522, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 2535. Themethod of claim 2522, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 2536. The method of claim2522, further comprising producing a mixture from the formation, whereinthe produced mixture comprises non-condensable hydrocarbons, and whereina molar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2537. The method of claim 2522,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 2538. The method of claim 2522,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2539. The method of claim 2522,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 2540. The method of claim 2522,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2541. The method of claim 2522, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 2542.The method of claim 2522, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2543. The method of claim 2522, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 2544. The method of claim2522, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2545. The method of claim 2522, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2546. The method of claim 2522, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2547. The method of claim2522, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2548. The method of claim 2522, furthercomprising controlling a pressure within at least a majority of aselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 2549. The method of claim 2522, wherein apartial pressure of H₂ within the mixture is greater than about 0.5bars.
 2550. The method of claim 2522, further comprising producing amixture from the formation, wherein a partial pressure of H₂ within themixture is measured when the mixture is at a production well.
 2551. Themethod of claim 2522, further comprising altering a pressure within theformation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than about
 25. 2552. The method of claim2522, further comprising producing a mixture from the formation andcontrolling formation conditions by recirculating a portion of hydrogenfrom the mixture into the formation.
 2553. The method of claim 2522,further comprising: providing hydrogen (H₂) to the portion tohydrogenate hydrocarbons within the formation; and heating a portion ofthe formation with heat from hydrogenation.
 2554. The method of claim2522, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2555. The method of claim 2522, further comprisingallowing heat to transfer from the heat sources to a selected section ofthe formation to pyrolyze at least some hydrocarbons within the selectedsection such that a permeability of a majority of a selected section ofthe formation increases to greater than about 100 millidarcy.
 2556. Themethod of claim 2522, further comprising allowing heat to transfer fromthe heat sources to a selected section of the formation to pyrolyze atleast some hydrocarbons within the selected section such that apermeability of a majority of the selected section increasessubstantially uniformly.
 2557. The method of claim 2522, furthercomprising controlling the heat to yield greater than about 60% byweight of condensable hydrocarbons, as measured by Fischer Assay. 2558.The method of claim 2522, further comprising producing a mixture in aproduction well, and wherein at least about 7 heat sources are disposedin the formation for each production well.
 2559. The method of claim2558, wherein at least about 20 heat sources are disposed in theformation for each production well.
 2560. The method of claim 2522,further comprising forming a production well in the formation usingmagnetic tracking such that the production well is substantiallyparallel to the first wellbore and coupling a wellhead to the thirdwellbore.
 2561. The method of claim 2522, further comprising providingheat from three or more heat sources to at least a portion of theformation, wherein three or more of the heat sources are located in theformation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 2562. The method of claim 2522,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 2563. A method for installing aheater well into an oil shale formation, comprising: forming a bore inthe ground using a steerable motor and an accelerometer; and providing aheat source within the bore such that the heat source can transfer heatto at least a portion of the formation.
 2564. The method of claim 2563,further comprising installing at least two heater wells, and whereinsuperposition of heat from at least the two heater wells pyrolyzes atleast some hydrocarbons within a selected section of the formation.2565. The method of claim 2563, further comprising maintaining atemperature within a selected section within a pyrolysis temperaturerange.
 2566. The method of claim 2563, wherein the heat source comprisesan electrical heater.
 2567. The method of claim 2563, wherein the heatsource comprises a surface burner.
 2568. The method of claim 2563,wherein the heat source comprises a flameless distributed combustor.2569. The method of claim 2563, wherein the heat source comprises anatural distributed combustor.
 2570. The method of claim 2563, furthercomprising controlling a pressure and a temperature within at least amajority of a selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2571. The method of claim 2563,further comprising controlling the heat from the heat source such thatheat transferred from the heat source to at least the portion of theformation is less than about 1° C. per day during pyrolysis.
 2572. Themethod of claim 2563, further comprising: heating a selected volume (V)of the oil shale formation from the heat source, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day provided to the volume is equal to orless than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 2573. The methodof claim 2563, further comprising allowing the heat to transfer from theheat source to at least the portion of the formation substantially byconduction.
 2574. The method of claim 2563, further comprising providingheat from the heat source to at least the portion of the formation suchthat a thermal conductivity of at least the portion of the formation isgreater than about 0.5 W/(m ° C.).
 2575. The method of claim 2563,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 2576. The method of claim 2563, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 0.1% byweight to about 15% by weight of the condensable hydrocarbons areolefins.
 2577. The method of claim 2563, further comprising producing amixture from the formation, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 2578. The method of claim 2563, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 2579. The method of claim 2563, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2580. The method of claim 2563, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons issulfur.
 2581. The method of claim 2563, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.2582. The method of claim 2563, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2583. The method ofclaim 2563, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2584. Themethod of claim 2563, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2585. The method of claim2563, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2586. The method of claim 2563, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2587. The method of claim 2563, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2588. The method of claim2563, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2589. The method of claim 2563, furthercomprising controlling a pressure within at least a majority of aselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 2590. The method of claim 2563, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bars.
 2591. The method of claim 2563, wherein apartial pressure of H₂ within the mixture is measured when the mixtureis at a production well.
 2592. The method of claim 2563, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 2593. The method of claim 2563, furthercomprising producing a mixture from the formation and controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2594. The method of claim 2563, furthercomprising: providing hydrogen (H₂) to the at least the heated portionto hydrogenate hydrocarbons within the formation; and heating a portionof the formation with heat from hydrogenation.
 2595. The method of claim2563, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2596. The method of claim 2563, further comprisingallowing heat to transfer from the heat source to a selected section ofthe formation to pyrolyze at least some hydrocarbons within the selectedsection such that a permeability of a majority of a selected section ofthe formation increases to greater than about 100 millidarcy.
 2597. Themethod of claim 2563, further comprising allowing heat to transfer fromthe heat source to a selected section of the formation to pyrolyze atleast some hydrocarbons within the selected section such that apermeability of a majority of the selected section increasessubstantially uniformly.
 2598. The method of claim 2563, furthercomprising controlling the heat to yield greater than about 60% byweight of condensable hydrocarbons, as measured by Fischer Assay. 2599.The method of claim 2563, further comprising producing a mixture in aproduction well, and wherein at least about 7 heat sources are disposedin the formation for each production well.
 2600. The method of claim2599, wherein at least about 20 heat sources are disposed in theformation for each production well.
 2601. The method of claim 2563,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 2602.The method of claim 2563, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 2603. A methodfor installing of wells in an oil shale formation, comprising: forming awellbore in the formation by geosteered drilling; and providing a heatsource within the wellbore such that the heat source can transfer heatto at least a portion of the formation.
 2604. The method of claim 2603,further comprising maintaining a temperature within a selected sectionwithin a pyrolysis temperature range.
 2605. The method of claim 2603,wherein the heat source comprises an electrical heater.
 2606. The methodof claim 2603, wherein the heat source comprises a surface burner. 2607.The method of claim 2603, wherein the heat source comprises a flamelessdistributed combustor.
 2608. The method of claim 2603, wherein the heatsource comprises a natural distributed combustor.
 2609. The method ofclaim 2603, further comprising controlling a pressure and a temperaturewithin at least a majority of a selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 2610. The method ofclaim 2603, further comprising controlling the heat from the heat sourcesuch that heat transferred from the heat source to at least the portionof the formation is less than about 1° C. per day during pyrolysis.2611. The method of claim 2603, further comprising: heating a selectedvolume (V) of the oil shale formation from the heat source, wherein theformation has an average heat capacity (C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day provided to the volume isequal to or less than Pwr, wherein Pwr is calculated by the equation:Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is anaverage heating rate of the formation, ρ_(B) is formation bulk density,and wherein the heating rate is less than about 10° C./day.
 2612. Themethod of claim 2603, further comprising allowing the heat to transferfrom the heat source to at least the portion of the formationsubstantially by conduction.
 2613. The method of claim 2603, furthercomprising providing heat from the heat source to at least the portionof the formation such that a thermal conductivity of at least theportion of the formation is greater than about 0.5 W/(m ° C.).
 2614. Themethod of claim 2603, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 2615. Themethod of claim 2603, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 2616. The method of claim2603, further comprising producing a mixture from the formation, whereinthe produced mixture comprises non-condensable hydrocarbons, and whereina molar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2617. The method of claim 2603,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 2618. The method of claim 2603,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2619. The method of claim 2603,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 2620. The method of claim 2603,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2621. The method of claim 2603, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 2622.The method of claim 2603, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2623. The method of claim 2603, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 2624. The method of claim2603, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2625. The method of claim 2603, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2626. The method of claim 2603, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2627. The method of claim2603, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2628. The method of claim 2603, furthercomprising controlling a pressure within at least a majority of aselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 2629. The method of claim 2603, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bars.
 2630. The method of claim 2629, wherein thepartial pressure of H₂ within the mixture is measured when the mixtureis at a production well.
 2631. The method of claim 2603, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 2632. The method of claim 2603, furthercomprising producing a mixture from the formation and controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2633. The method of claim 2603, furthercomprising: providing hydrogen (H₂) to at least the heated portion tohydrogenate hydrocarbons within the formation; and heating a portion ofthe formation with heat from hydrogenation.
 2634. The method of claim2603, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2635. The method of claim 2603, further comprisingallowing heat to transfer from the heat source to a selected section ofthe formation to pyrolyze at least some hydrocarbons within the selectedsection such that a permeability of a majority of a selected section ofthe formation increases to greater than about 100 millidarcy.
 2636. Themethod of claim 2603, further comprising allowing heat to transfer fromthe heat source to a selected section of the formation to pyrolyze atleast some hydrocarbons within the selected section such that apermeability of a majority of the selected section increasessubstantially uniformly.
 2637. The method of claim 2603, furthercomprising controlling the heat to yield greater than about 60% byweight of condensable hydrocarbons, as measured by Fischer Assay. 2638.The method of claim 2603, further comprising producing a mixture in aproduction well, and wherein at least about 7 heat sources are disposedin the formation for each production well.
 2639. The method of claim2638, wherein at least about 20 heat sources are disposed in theformation for each production well.
 2640. The method of claim 2603,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 2641.The method of claim 2603, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 2642. A methodof treating an oil shale formation in situ, comprising: heating aselected section of the formation with a heating element placed within awellbore, wherein at least one end of the heating element is free tomove axially within the wellbore to allow for thermal expansion of theheating element.
 2643. The method of claim 2642, further comprising atleast two heating elements within at least two wellbores, and whereinsuperposition of heat from at least the two heating elements pyrolyzesat least some hydrocarbons within a selected section of the formation.2644. The method of claim 2642, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 2645. The method of claim 2642, wherein the heating elementcomprises a pipe-in-pipe heater.
 2646. The method of claim 2642, whereinthe heating element comprises a flameless distributed combustor. 2647.The method of claim 2642, wherein the heating element comprises amineral insulated cable coupled to a support, and wherein the support isfree to move within the wellbore.
 2648. The method of claim 2642,wherein the heating element comprises a mineral insulated cablesuspended from a wellhead.
 2649. The method of claim 2642, furthercomprising controlling a pressure and a temperature within at least amajority of a heated section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2650. The method of claim 2642,further comprising controlling the heat such that an average heatingrate of the heated section is less than about 1° C. per day duringpyrolysis.
 2651. The method of claim 2642, wherein heating the sectionof the formation further comprises: heating a selected volume (V) of theoil shale formation from the heating element, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 2652. The methodof claim 2642, wherein heating the section of the formation comprisestransferring heat substantially by conduction.
 2653. The method of claim2642, further comprising heating the selected section of the formationsuch that a thermal conductivity of the selected section is greater thanabout 0.5 W/(m ° C.).
 2654. The method of claim 2642, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 2655. The method of claim 2642, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein about 0.1% by weight to about 15%by weight of the condensable hydrocarbons are olefins.
 2656. The methodof claim 2642, further comprising producing a mixture from theformation, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.2657. The method of claim 2642, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2658.The method of claim 2642, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 2659. Themethod of claim 2642, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 2660. Themethod of claim 2642, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2661. Themethod of claim 2642, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2662. The method ofclaim 2642, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2663. Themethod of claim 2642, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2664. The method of claim2642, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2665. The method of claim 2642, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2666. The method of claim 2642, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2667. The method of claim2642, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2668. The method of claim 2642, furthercomprising controlling a pressure within the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 2669. The method of claim 2642, further comprising controllingformation conditions to produce a mixture from the formation, wherein apartial pressure of H₂ within the mixture is greater than about 0.5bars.
 2670. The method of claim 2669, wherein the partial pressure of H₂within the mixture is measured when the mixture is at a production well.2671. The method of claim 2642, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 2672. The methodof claim 2642, further comprising producing a mixture from the formationand controlling formation conditions by recirculating a portion ofhydrogen from the mixture into the formation.
 2673. The method of claim2642, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the heated section; and heating aportion of the section with heat from hydrogenation.
 2674. The method ofclaim 2642, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2675. The method of claim 2642, wherein heatingcomprises increasing a permeability of a majority of the heated sectionto greater than about 100 millidarcy.
 2676. The method of claim 2642,wherein heating comprises substantially uniformly increasing apermeability of a majority of the heated section.
 2677. The method ofclaim 2642, wherein the heating is controlled to yield greater thanabout 60% by weight of condensable hydrocarbons, as measured by FischerAssay.
 2678. The method of claim 2642, further comprising producing amixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 2679. The methodof claim 2678, wherein at least about 20 heat sources are disposed inthe formation for each production well.
 2680. The method of claim 2642,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 2681.The method of claim 2642, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 2682. A methodof treating an oil shale formation in situ, comprising: providing heatfrom one or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; and producing a mixture from theformation through a production well, wherein the production well islocated such that a majority of the mixture produced from the formationcomprises non-condensable hydrocarbons and a non-condensable componentcomprising hydrogen.
 2683. The method of claim 2682, wherein the one ormore heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.2684. The method of claim 2682, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 2685. The method of claim 2682, wherein the production well isless than approximately 6 m from a heat source of the one or more heatsources.
 2686. The method of claim 2682, wherein the production well isless than approximately 3 m from a heat source of the one or more heatsources.
 2687. The method of claim 2682, wherein the production well isless than approximately 1.5 m from a heat source of the one or more heatsources.
 2688. The method of claim 2682, wherein an additional heatsource is positioned within a wellbore of the production well.
 2689. Themethod of claim 2682, wherein the one or more heat sources compriseelectrical heaters.
 2690. The method of claim 2682, wherein the one ormore heat sources comprise surface burners.
 2691. The method of claim2682, wherein the one or more heat sources comprise flamelessdistributed combustors.
 2692. The method of claim 2682, wherein the oneor more heat sources comprise natural distributed combustors.
 2693. Themethod of claim 2682, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.2694. The method of claim 2682, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 2695. The method of claim 2682,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of the oilshale formation from the one or more heat sources, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day provided to the volume is equal to orless than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 2696. The methodof claim 2682, wherein allowing the heat to transfer from the one ormore heat sources to the selected section comprises transferring heatsubstantially by conduction.
 2697. The method of claim 2682, whereinproviding heat from the one or more heat sources comprises heating theselected section such that a thermal conductivity of at least a portionof the selected section is greater than about 0.5 W/(m ° C.).
 2698. Themethod of claim 2682, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 2699. Themethod of claim 2682, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 2700. The method of claim2682, wherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 2701. The method ofclaim 2682, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2702.The method of claim 2682, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2703. The method of claim 2682, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 2704. The method of claim 2682, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2705. The method of claim 2682, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 2706. The method of claim 2682, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 2707. The method of claim 2682, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 2708. The method of claim 2682, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 2709. The method of claim 2682, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2710. The method of claim 2682, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 2711. The method of claim2682, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 2712. The method of claim 2682,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 2713. The method of claim 2682,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 2714. The method of claim 2713, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2715. The method of claim 2682, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2716. The method of claim 2682, further comprising controllingformation conditions by recirculating a portion of the hydrogen from themixture into the formation.
 2717. The method of claim 2682, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 2718. The method of claim 2682, furthercomprising: producing condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2719. The method of claim2682, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 2720. The method of claim 2682, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 2721. The method ofclaim 2682, further comprising controlling the heat to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured byFischer Assay.
 2722. The method of claim 2682, wherein producing themixture comprises producing the mixture in a production well, andwherein at least about 7 heat sources are disposed in the formation foreach production well.
 2723. The method of claim 2722, wherein at leastabout 20 heat sources are disposed in the formation for each productionwell.
 2724. The method of claim 2682, further comprising providing heatfrom three or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 2725. The method of claim 2682, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 2726. A method of treating an oil shaleformation in situ, comprising: providing heat to at least a portion ofthe formation from one or more first heat sources placed within apattern in the formation; allowing the heat to transfer from the one ormore first heat sources to a first section of the formation; heating asecond section of the formation with at least one second heat source,wherein the second section is located within the first section, andwherein at least the one second heat source is configured to raise anaverage temperature of a portion of the second section to a highertemperature than an average temperature of the first section; andproducing a mixture from the formation through a production wellpositioned within the second section, wherein a majority of the producedmixture comprises non-condensable hydrocarbons and a non-condensablecomponent comprising H₂ components.
 2727. The method of claim 2726,wherein the one or more first heat sources comprise at least two heatsources, and wherein superposition of heat from at least the two heatsources pyrolyzes at least some hydrocarbons within the first section ofthe formation.
 2728. The method of claim 2726, further comprisingmaintaining a temperature within the first section within a pyrolysistemperature range.
 2729. The method of claim 2726, wherein at least theone heat source comprises a heater element positioned within theproduction well.
 2730. The method of claim 2726, wherein at least theone second heat source comprises an electrical heater.
 2731. The methodof claim 2726, wherein at least the one second heat source comprises asurface burner.
 2732. The method of claim 2726, wherein at least the onesecond heat source comprises a flameless distributed combustor. 2733.The method of claim 2726, wherein at least the one second heat sourcecomprises a natural distributed combustor.
 2734. The method of claim2726, further comprising controlling a pressure and a temperature withinat least a majority of the first or the second section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 2735. The method ofclaim 2726, further comprising controlling the heat such that an averageheating rate of the first section is less than about 1° C. per dayduring pyrolysis.
 2736. The method of claim 2726, wherein providing heatto the formation further comprises: heating a selected volume (V) of theoil shale formation from the one or more first heat sources, wherein theformation has an average heat capacity (C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day provided to the volume isequal to or less than Pwr, wherein Pwr is calculated by the equation:Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is anaverage heating rate of the formation, ρ_(B) is formation bulk density,and wherein the heating rate is less than about 10° C./day.
 2737. Themethod of claim 2726, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 2738. The method of claim2726, wherein providing heat from the one or more first heat sourcescomprises heating the first section such that a thermal conductivity ofat least a portion of the first section is greater than about 0.5 W/(m °C.).
 2739. The method of claim 2726, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 2740. The method of claim 2726, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 2741.The method of claim 2726, wherein a molar ratio of ethene to ethane inthe non-condensable hydrocarbons ranges from about 0.001 to about 0.15.2742. The method of claim 2726, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 2743. The method of claim 2726, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 2744. The method of claim 2726, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 2745. The method of claim 2726,wherein the produced mixture comprises condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 2746. The method of claim2726, wherein the produced mixture comprises condensable hydrocarbons,and wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 2747. The method of claim 2726,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2748. Themethod of claim 2726, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2749. The method of claim2726, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2750. The method of claim 2726, whereinthe produced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2751. The method of claim 2726, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 2752. The method of claim2726, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 2753. The method of claim 2726,further comprising controlling a pressure within at least a majority ofthe first or the second section of the formation, wherein the controlledpressure is at least about 2.0 bars absolute.
 2754. The method of claim2726, further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 2755. The method of claim 2754, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2756. The method of claim 2726, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2757. The method of claim 2726, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2758. The method of claim 2726, furthercomprising: providing hydrogen (H₂) to the first or second section tohydrogenate hydrocarbons within the first or second section,respectively; and heating a portion of the first or second section,respectively, with heat from hydrogenation.
 2759. The method of claim2726, further comprising: producing condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 2760. Themethod of claim 2726, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the first or second sectionto greater than about 100 millidarcy.
 2761. The method of claim 2726,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the first or second section.2762. The method of claim 2726, wherein heating the first or the secondsection is controlled to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 2763. The methodof claim 2726, wherein at least about 7 heat sources are disposed in theformation for each production well.
 2764. The method of claim 2763,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 2765. The method of claim 2726, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 2766. The method of claim 2726,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 2767. A method of treating an oilshale formation in situ, comprising: providing heat into the formationfrom a plurality of heat sources placed in a pattern within theformation, wherein a spacing between heat sources is greater than about6 m; allowing the heat to transfer from the plurality of heat sources toa selected section of the formation; and producing a mixture from theformation from a plurality of production wells, wherein the plurality ofproduction wells are positioned within the pattern, and wherein aspacing between production wells is greater than about 12 m.
 2768. Themethod of claim 2767, wherein superposition of heat from the pluralityof heat sources pyrolyzes at least some hydrocarbons within the selectedsection of the formation.
 2769. The method of claim 2767, furthercomprising maintaining a temperature within the selected section withina pyrolysis temperature range.
 2770. The method of claim 2767, whereinthe plurality of heat sources comprises electrical heaters.
 2771. Themethod of claim 2767, wherein the plurality of heat sources comprisessurface burners.
 2772. The method of claim 2767, wherein the pluralityof heat sources comprises flameless distributed combustors.
 2773. Themethod of claim 2767, wherein the plurality of heat sources comprisesnatural distributed combustors.
 2774. The method of claim 2767, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2775. The method of claim 2767,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2776. The method of claim 2767, wherein providing heat fromthe plurality of heat sources comprises: heating a selected volume (V)of the oil shale formation from the plurality of heat sources, whereinthe formation has an average heat capacity (C_(v)), and wherein theheating pyrolyzes at least some hydrocarbons within the selected volumeof the formation; and wherein heating energy/day provided to the volumeis equal to or less than Pwr, wherein Pwr is calculated by the equation:Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is anaverage heating rate of the formation, ρ_(B) is formation bulk density,and wherein the heating rate is less than about 10° C./day.
 2777. Themethod of claim 2767, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 2778. The method of claim2767, wherein providing heat comprises heating the selected formationsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 2779. The method of claim2767, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 2780. The method of claim2767, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 2781. The method of claim 2767,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 2782. The method ofclaim 2767, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2783.The method of claim 2767, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2784. The method of claim 2767, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 2785. The method of claim 2767, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2786. The method of claim 2767, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 2787. The method of claim 2767, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 2788. The method of claim 2767, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 2789. The method of claim 2767, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 2790. The method of claim 2767, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2791. The method of claim 2767, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 2792. The method of claim2767, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 2793. The method of claim 2767,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 2794. The method of claim 2767,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 2795. The method of claim 2794, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2796. The method of claim 2767, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2797. The method of claim 2767, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2798. The method of claim 2767, furthercomprising: providing hydrogen (H₂) to the selected section tohydrogenate hydrocarbons within the selected section; and heating aportion of the selected section with heat from hydrogenation.
 2799. Themethod of claim 2767, further comprising: producing hydrogen andcondensable hydrocarbons from the formation; and hydrogenating a portionof the produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2800. The method of claim 2767, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 2801. Themethod of claim 2767, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 2802. The method of claim 2767, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by Fischer Assay.
 2803. The methodof claim 2767, wherein at least about 7 heat sources are disposed in theformation for each production well.
 2804. The method of claim 2803,wherein at least about 20 heat sources are disposed in the formation foreach production well.
 2805. The method of claim 2767, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 2806. The method of claim 2767,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 2807. A system configured to heat anoil shale formation, comprising: a heater disposed in an opening in theformation, wherein the heater is configured to provide heat to at leasta portion of the formation during use; an oxidizing fluid source; aconduit disposed in the opening, wherein the conduit is configured toprovide an oxidizing fluid from the oxidizing fluid source to a reactionzone in the formation during use, and wherein the oxidizing fluid isselected to oxidize at least some hydrocarbons at the reaction zoneduring use such that heat is generated at the reaction zone; and whereinthe system is configured to allow heat to transfer substantially byconduction from the reaction zone to a pyrolysis zone of the formationduring use.
 2808. The system of claim 2807, wherein the oxidizing fluidis configured to generate heat in the reaction zone such that theoxidizing fluid is transported through the reaction zone substantiallyby diffusion.
 2809. The system of claim 2807, wherein the conduitcomprises orifices, and wherein the orifices are configured to providethe oxidizing fluid into the opening.
 2810. The system of claim 2807,wherein the conduit comprises critical flow orifices, and wherein thecritical flow orifices are configured to control a flow of the oxidizingfluid such that a rate of oxidation in the formation is controlled.2811. The system of claim 2807, wherein the conduit is furtherconfigured to be cooled with the oxidizing fluid such that the conduitis not substantially heated by oxidation.
 2812. The system of claim2807, wherein the conduit is further configured to remove an oxidationproduct.
 2813. The system of claim 2807, wherein the conduit is furtherconfigured to remove an oxidation product such that the oxidationproduct transfers substantial heat to the oxidizing fluid.
 2814. Thesystem of claim 2807, wherein the conduit is further configured toremove an oxidation product, and wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 2815. The system of claim 2807,wherein the conduit is further configured to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the conduitand a pressure of the oxidation product in the conduit are controlled toreduce contamination of the oxidation product by the oxidizing fluid.2816. The system of claim 2807, wherein the conduit is furtherconfigured to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 2817. The system of claim 2807,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 2818. The system ofclaim 2807, further comprising a center conduit disposed within theconduit, wherein the center conduit is configured to provide theoxidizing fluid into the opening during use, and wherein the conduit isfurther configured to remove an oxidation product during use.
 2819. Thesystem of claim 2807, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.2820. The system of claim 2807, further comprising a conductor disposedin a second conduit, wherein the second conduit is disposed within theopening, and wherein the conductor is configured to heat at least aportion of the formation during application of an electrical current tothe conductor.
 2821. The system of claim 2807, further comprising aninsulated conductor disposed within the opening, wherein the insulatedconductor is configured to heat at least a portion of the formationduring application of an electrical current to the insulated conductor.2822. The system of claim 2807, further comprising at least oneelongated member disposed within the opening, wherein the at least theone elongated member is configured to heat at least a portion of theformation during application of an electrical current to the at leastthe one elongated member.
 2823. The system of claim 2807, furthercomprising a heat exchanger disposed external to the formation, whereinthe heat exchanger is configured to heat the oxidizing fluid, whereinthe conduit is further configured to provide the heated oxidizing fluidinto the opening during use, and wherein the heated oxidizing fluid isconfigured to heat at least a portion of the formation during use. 2824.The system of claim 2807, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 2825. The system of claim 2807, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 2826. The system of claim2807, farther comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 2827. The system of claim 2807, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 2828. The system ofclaim 2807, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 2829. The system of claim2807, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 2830. The system of claim 2807, wherein the system isfurther configured such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 2831. A system configurable to heatan oil shale formation, comprising: a heater configurable to be disposedin an opening in the formation, wherein the heater is furtherconfigurable to provide heat to at least a portion of the formationduring use; a conduit configurable to be disposed in the opening,wherein the conduit is configurable to provide an oxidizing fluid froman oxidizing fluid source to a reaction zone in the formation duringuse, and wherein the system is configurable to allow the oxidizing fluidto oxidize at least some hydrocarbons at the reaction zone during usesuch that heat is generated at the reaction zone; and wherein the systemis further configurable to allow heat to transfer substantially byconduction from the reaction zone to a pyrolysis zone of the formationduring use.
 2832. The system of claim 2831, wherein the oxidizing fluidis configurable to generate heat in the reaction zone such that theoxidizing fluid is transported through the reaction zone substantiallyby diffusion.
 2833. The system of claim 2831, wherein the conduitcomprises orifices, and wherein the orifices are configurable to providethe oxidizing fluid into the opening.
 2834. The system of claim 2831,wherein the conduit comprises critical flow orifices, and wherein thecritical flow orifices are configurable to control a flow of theoxidizing fluid such that a rate of oxidation in the formation iscontrolled.
 2835. The system of claim 2831, wherein the conduit isfurther configurable to be cooled with the oxidizing fluid such that theconduit is not substantially heated by oxidation.
 2836. The system ofclaim 2831, wherein the conduit is further configurable to remove anoxidation product.
 2837. The system of claim 2831, wherein the conduitis further configurable to remove an oxidation product, such that theoxidation product transfers heat to the oxidizing fluid.
 2838. Thesystem of claim 2831, wherein the conduit is further configurable toremove an oxidation product, and wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 2839. The system of claim 2831,wherein the conduit is further configurable to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the conduitand a pressure of the oxidation product in the conduit are controlled toreduce contamination of the oxidation product by the oxidizing fluid.2840. The system of claim 2831, wherein the conduit is furtherconfigurable to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 2841. The system of claim 2831,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 2842. The system ofclaim 2831, further comprising a center conduit disposed within theconduit, wherein the center conduit is configurable to provide theoxidizing fluid into the opening during use, and wherein the conduit isfurther configurable to remove an oxidation product during use. 2843.The system of claim 2831, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.2844. The system of claim 2831, further comprising a conductor disposedin a second conduit, wherein the second conduit is disposed within theopening, and wherein the conductor is configurable to heat at least aportion of the formation during application of an electrical current tothe conductor.
 2845. The system of claim 2831, further comprising aninsulated conductor disposed within the opening, wherein the insulatedconductor is configurable to heat at least a portion of the formationduring application of an electrical current to the insulated conductor.2846. The system of claim 2831, further comprising at least oneelongated member disposed within the opening, wherein the at least theone elongated member is configurable to heat at least a portion of theformation during application of an electrical current to the at leastthe one elongated member.
 2847. The system of claim 2831, furthercomprising a heat exchanger disposed external to the formation, whereinthe heat exchanger is configurable to heat the oxidizing fluid, whereinthe conduit is further configurable to provide the heated oxidizingfluid into the opening during use, and wherein the heated oxidizingfluid is configurable to heat at least a portion of the formation duringuse.
 2848. The system of claim 2831, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation.
 2849. The system of claim 2831,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 2850. The system of claim2831, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 2851. The system of claim 2831, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 2852. The system ofclaim 2831, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configurable to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 2853. The system of claim2831, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 2854. The system of claim 2831, wherein the system isfurther configurable such that transferred heat can pyrolyze at leastsome hydrocarbons in the pyrolysis zone.
 2855. The system of claim 2831,wherein the system is configured to heat an oil shale formation, andwherein the system comprises: a heater disposed in an opening in theformation, wherein the heater is configured to provide heat to at leasta portion of the formation during use; an oxidizing fluid source; aconduit disposed in the opening, wherein the conduit is configured toprovide an oxidizing fluid from the oxidizing fluid source to a reactionzone in the formation during use, and wherein the oxidizing fluid isselected to oxidize at least some hydrocarbons at the reaction zoneduring use such that heat is generated at the reaction zone; and whereinthe system is configured to allow heat to transfer substantially byconduction from the reaction zone to a pyrolysis zone of the formationduring use.
 2856. An in situ method for heating an oil shale formation,comprising: heating a portion of the formation to a temperaturesufficient to support reaction of hydrocarbons within the portion of theformation with an oxidizing fluid; providing the oxidizing fluid to areaction zone in the formation; allowing the oxidizing fluid to reactwith at least a portion of the hydrocarbons at the reaction zone togenerate heat at the reaction zone; and transferring the generated heatsubstantially by conduction from the reaction zone to a pyrolysis zonein the formation.
 2857. The method of claim 2856, further comprisingtransporting the oxidizing fluid through the reaction zone by diffusion.2858. The method of claim 2856, further comprising directing at least aportion of the oxidizing fluid into the opening through orifices of aconduit disposed in the opening.
 2859. The method of claim 2856, furthercomprising controlling a flow of the oxidizing fluid with critical floworifices of a conduit disposed in the opening such that a rate ofoxidation is controlled.
 2860. The method of claim 2856, furthercomprising increasing a flow of the oxidizing fluid in the opening toaccommodate an increase in a volume of the reaction zone such that arate of oxidation is substantially constant over time within thereaction zone.
 2861. The method of claim 2856, wherein a conduit isdisposed in the opening, the method further comprising cooling theconduit with the oxidizing fluid to reduce heating of the conduit byoxidation.
 2862. The method of claim 2856, wherein a conduit is disposedwithin the opening, the method further comprising removing an oxidationproduct from the formation through the conduit.
 2863. The method ofclaim 2856, wherein a conduit is disposed within the opening, the methodfurther comprising removing an oxidation product from the formationthrough the conduit and transferring heat from the oxidation product inthe conduit to oxidizing fluid in the conduit.
 2864. The method of claim2856, wherein a conduit is disposed within the opening, the methodfurther comprising removing an oxidation product from the formationthrough the conduit, wherein a flow rate of the oxidizing fluid in theconduit is approximately equal to a flow rate of the oxidation productin the conduit.
 2865. The method of claim 2856, wherein a conduit isdisposed within the opening, the method further comprising removing anoxidation product from the formation through the conduit and controllinga pressure between the oxidizing fluid and the oxidation product in theconduit to reduce contamination of the oxidation product by theoxidizing fluid.
 2866. The method of claim 2856, wherein a conduit isdisposed within the opening, the method further comprising removing anoxidation product from the formation through the conduit andsubstantially inhibiting the oxidation product from flowing intoportions of the formation beyond the reaction zone.
 2867. The method ofclaim 2856, further comprising substantially inhibiting the oxidizingfluid from flowing into portions of the formation beyond the reactionzone.
 2868. The method of claim 2856, wherein a center conduit isdisposed within an outer conduit, and wherein the outer conduit isdisposed within the opening, the method further comprising providing theoxidizing fluid into the opening through the center conduit and removingan oxidation product through the outer conduit.
 2869. The method ofclaim 2856, wherein the portion of the formation extends radially fromthe opening a width of less than approximately 0.2 m.
 2870. The methodof claim 2856, wherein heating the portion comprises applying electricalcurrent to a conductor disposed in a conduit, wherein the conduit isdisposed within the opening.
 2871. The method of claim 2856, whereinheating the portion comprises applying electrical current to aninsulated conductor disposed within the opening.
 2872. The method ofclaim 2856, wherein heating the portion comprises applying electricalcurrent to at least one elongated member disposed within the opening.2873. The method of claim 2856, wherein heating the portion comprisesheating the oxidizing fluid in a heat exchanger disposed external to theformation such that providing the oxidizing fluid into the openingcomprises transferring heat from the heated oxidizing fluid to theportion.
 2874. The method of claim 2856, further comprising removingwater from the formation prior to heating the portion.
 2875. The methodof claim 2856, further comprising controlling the temperature of theformation to substantially inhibit production of oxides of nitrogenduring oxidation.
 2876. The method of claim 2856, further comprisingcoupling an overburden casing to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 2877. The methodof claim 2856, further comprising coupling an overburden casing to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 2878.The method of claim 2856, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 2879. The method of claim 2856, furthercomprising coupling an overburden casing to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 2880. The method of claim 2856, wherein the pyrolysis zoneis substantially adjacent to the reaction zone.
 2881. A systemconfigured to heat an oil shale formation, comprising: a heater disposedin an opening in the formation, wherein the heater is configured toprovide heat to at least a portion of the formation during use; anoxidizing fluid source; a conduit disposed in the opening, wherein theconduit is configured to provide an oxidizing fluid from the oxidizingfluid source to a reaction zone in the formation during use, wherein theoxidizing fluid is selected to oxidize at least some hydrocarbons at thereaction zone during use such that heat is generated at the reactionzone, and wherein the conduit is further configured to remove anoxidation product from the formation during use; and wherein the systemis configured to allow heat to transfer substantially by conduction fromthe reaction zone to a pyrolysis zone of the formation during use. 2882.The system of claim 2881, wherein the oxidizing fluid is configured togenerate heat in the reaction zone such that the oxidizing fluid istransported through the reaction zone substantially by diffusion. 2883.The system of claim 2881, wherein the conduit comprises orifices, andwherein the orifices are configured to provide the oxidizing fluid intothe opening.
 2884. The system of claim 2881, wherein the conduitcomprises critical flow orifices, and wherein the critical flow orificesare configured to control a flow of the oxidizing fluid such that a rateof oxidation in the formation is controlled.
 2885. The system of claim2881, wherein the conduit is further configured to be cooled with theoxidizing fluid such that the conduit is not substantially heated byoxidation.
 2886. The system of claim 2881, wherein the conduit isfurther configured such that the oxidation product transfers heat to theoxidizing fluid.
 2887. The system of claim 2881, wherein a flow rate ofthe oxidizing fluid in the conduit is approximately equal to a flow rateof the oxidation product in the conduit.
 2888. The system of claim 2881,wherein a pressure of the oxidizing fluid in the conduit and a pressureof the oxidation product in the conduit are controlled to reducecontamination of the oxidation product by the oxidizing fluid.
 2889. Thesystem of claim 2881, wherein the oxidation product is substantiallyinhibited from flowing into portions of the formation beyond thereaction zone.
 2890. The system of claim 2881, wherein the oxidizingfluid is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 2891. The system of claim 2881,further comprising a center conduit disposed within the conduit, whereinthe center conduit is configured to provide the oxidizing fluid into theopening during use.
 2892. The system of claim 2881, wherein the portionof the formation extends radially from the opening a width of less thanapproximately 0.2 m.
 2893. The system of claim 2881, further comprisinga conductor disposed in a second conduit, wherein the second conduit isdisposed within the opening, and wherein the conductor is configured toheat at least a portion of the formation during application of anelectrical current to the conductor.
 2894. The system of claim 2881,further comprising an insulated conductor disposed within the opening,wherein the insulated conductor is configured to heat at least a portionof the formation during application of an electrical current to theinsulated conductor.
 2895. The system of claim 2881, further comprisingat least one elongated member disposed within the opening, wherein theat least the one elongated member is configured to heat at least aportion of the formation during application of an electrical current tothe at least the one elongated member.
 2896. The system of claim 2881,further comprising a heat exchanger disposed external to the formation,wherein the heat exchanger is configured to heat the oxidizing fluid,wherein the conduit is further configured to provide the heatedoxidizing fluid into the opening during use, and wherein the heatedoxidizing fluid is configured to heat at least a portion of theformation during use.
 2897. The system of claim 2881, further comprisingan overburden casing coupled to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 2898. The systemof claim 2881, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 2899.The system of claim 2881, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 2900. The system of claim 2881, furthercomprising an overburden casing coupled to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 2901. The system of claim 2881, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configured to substantiallyinhibit a flow of fluid between the opening and the overburden casingduring use.
 2902. The system of claim 2881, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material comprises cement.
 2903. Thesystem of claim 2881, wherein the system is further configured such thattransferred heat can pyrolyze at least some hydrocarbons in thepyrolysis zone.
 2904. A system configurable to heat an oil shaleformation, comprising: a heater configurable to be disposed in anopening in the formation, wherein the heater is further configurable toprovide heat to at least a portion of the formation during use; aconduit configurable to be disposed in the opening, wherein the conduitis further configurable to provide an oxidizing fluid from an oxidizingfluid source to a reaction zone in the formation during use, wherein thesystem is configurable to allow the oxidizing fluid to oxidize at leastsome hydrocarbons at the reaction zone during use such that heat isgenerated at the reaction zone, and wherein the conduit is furtherconfigurable to remove an oxidation product from the formation duringuse; and wherein the system is further configurable to allow heat totransfer substantially by conduction from the reaction zone to apyrolysis zone during use.
 2905. The system of claim 2904, wherein theoxidizing fluid is configurable to generate heat in the reaction zonesuch that the oxidizing fluid is transported through the reaction zonesubstantially by diffusion.
 2906. The system of claim 2904, wherein theconduit comprises orifices, and wherein the orifices are configurable toprovide the oxidizing fluid into the opening.
 2907. The system of claim2904, wherein the conduit comprises critical flow orifices, and whereinthe critical flow orifices are configurable to control a flow of theoxidizing fluid such that a rate of oxidation in the formation iscontrolled.
 2908. The system of claim 2904, wherein the conduit isfurther configurable to be cooled with the oxidizing fluid such that theconduit is not substantially heated by oxidation.
 2909. The system ofclaim 2904, wherein the conduit is further configurable such that theoxidation product transfers heat to the oxidizing fluid.
 2910. Thesystem of claim 2904, wherein a flow rate of the oxidizing fluid in theconduit is approximately equal to a flow rate of the oxidation productin the conduit.
 2911. The system of claim 2904, wherein a pressure ofthe oxidizing fluid in the conduit and a pressure of the oxidationproduct in the conduit are controlled to reduce contamination of theoxidation product by the oxidizing fluid.
 2912. The system of claim2904, wherein the oxidation product is substantially inhibited fromflowing into portions of the formation beyond the reaction zone. 2913.The system of claim 2904, wherein the oxidizing fluid is substantiallyinhibited from flowing into portions of the formation beyond thereaction zone.
 2914. The system of claim 2904, further comprising acenter conduit disposed within the conduit, wherein the center conduitis configurable to provide the oxidizing fluid into the opening duringuse.
 2915. The system of claim 2904, wherein the portion of theformation extends radially from the opening a width of less thanapproximately 0.2 m.
 2916. The system of claim 2904, further comprisinga conductor disposed in a second conduit, wherein the second conduit isdisposed within the opening, and wherein the conductor is configurableto heat at least a portion of the formation during application of anelectrical current to the conductor.
 2917. The system of claim 2904,further comprising an insulated conductor disposed within the opening,wherein the insulated conductor is configurable to heat at least aportion of the formation during application of an electrical current tothe insulated conductor.
 2918. The system of claim 2904, furthercomprising at least one elongated member disposed within the opening,wherein the at least the one elongated member is configurable to heat atleast a portion of the formation during application of an electricalcurrent to the at least the one elongated member.
 2919. The system ofclaim 2904, further comprising a heat exchanger disposed external to theformation, wherein the heat exchanger is configurable to heat theoxidizing fluid, wherein the conduit is further configurable to providethe heated oxidizing fluid into the opening during use, and wherein theheated oxidizing fluid is configurable to heat at least a portion of theformation during use.
 2920. The system of claim 2904, further comprisingan overburden casing coupled to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 2921. The systemof claim 2904, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 2922.The system of claim 2904, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 2923. The system of claim 2904, furthercomprising an overburden casing coupled to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 2924. The system of claim 2904, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 2925. The system of claim 2904, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.2926. The system of claim 2904, wherein the system is furtherconfigurable such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 2927. The system of claim 2904,wherein the system is configured to heat an oil shale formation, andwherein the system comprises: a heater disposed in an opening in theformation, wherein the heater is configured to provide heat to at leasta portion of the formation during use; an oxidizing fluid source; aconduit disposed in the opening, wherein the conduit is configured toprovide an oxidizing fluid from the oxidizing fluid source to a reactionzone in the formation during use, wherein the oxidizing fluid isselected to oxidize at least some hydrocarbons at the reaction zoneduring use such that heat is generated at the reaction zone, and whereinthe conduit is further configured to remove an oxidation product fromthe formation during use; and wherein the system is configured to allowheat to transfer substantially by conduction from the reaction zone to apyrolysis zone of the formation during use.
 2928. An in situ method forheating an oil shale formation, comprising: heating a portion of theformation to a temperature sufficient to support reaction ofhydrocarbons within the portion of the formation with an oxidizingfluid, wherein the portion is located substantially adjacent to anopening in the formation; providing the oxidizing fluid to a reactionzone in the formation; allowing the oxidizing gas to react with at leasta portion of the hydrocarbons at the reaction zone to generate heat inthe reaction zone; removing at least a portion of an oxidation productthrough the opening; and transferring the generated heat substantiallyby conduction from the reaction zone to a pyrolysis zone in theformation.
 2929. The method of claim 2928, further comprisingtransporting the oxidizing fluid through the reaction zone by diffusion.2930. The method of claim 2928, further comprising directing at least aportion of the oxidizing fluid into the opening through orifices of aconduit disposed in the opening.
 2931. The method of claim 2928, furthercomprising controlling a flow of the oxidizing fluid with critical floworifices of a conduit disposed in the opening such that a rate ofoxidation is controlled.
 2932. The method of claim 2928, furthercomprising increasing a flow of the oxidizing fluid in the opening toaccommodate an increase in a volume of the reaction zone such that arate of oxidation is substantially maintained within the reaction zone.2933. The method of claim 2928, wherein a conduit is disposed in theopening, the method further comprising cooling the conduit with theoxidizing fluid such that the conduit is not substantially heated byoxidation.
 2934. The method of claim 2928, wherein a conduit is disposedwithin the opening, and wherein removing at least the portion of theoxidation product through the opening comprises removing at least theportion of the oxidation product through the conduit.
 2935. The methodof claim 2928, wherein a conduit is disposed within the opening, andwherein removing at least the portion of the oxidation product throughthe opening comprises removing at least the portion of the oxidationproduct through the conduit, the method further comprising transferringsubstantial heat from the oxidation product in the conduit to theoxidizing fluid in the conduit.
 2936. The method of claim 2928, whereina conduit is disposed within the opening, wherein removing at least theportion of the oxidation product through the opening comprises removingat least the portion of the oxidation product through the conduit, andwherein a flow rate of the oxidizing fluid in the conduit isapproximately equal to a flow rate of the oxidation product in theconduit.
 2937. The method of claim 2928, wherein a conduit is disposedwithin the opening, and wherein removing at least the portion of theoxidation product through the opening comprises removing at least theportion of the oxidation product through the conduit, the method furthercomprising controlling a pressure between the oxidizing fluid and theoxidation product in the conduit to reduce contamination of theoxidation product by the oxidizing fluid.
 2938. The method of claim2928, wherein a conduit is disposed within the opening, and whereinremoving at least the portion of the oxidation product through theopening comprises removing at least the portion of the oxidation productthrough the conduit, the method further comprising substantiallyinhibiting the oxidation product from flowing into portions of theformation beyond the reaction zone.
 2939. The method of claim 2928,further comprising substantially inhibiting the oxidizing fluid fromflowing into portions of the formation beyond the reaction zone. 2940.The method of claim 2928, wherein a center conduit is disposed within anouter conduit, and wherein the outer conduit is disposed within theopening, the method further comprising providing the oxidizing fluidinto the opening through the center conduit and removing at least aportion of the oxidation product through the outer conduit.
 2941. Themethod of claim 2928, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.2942. The method of claim 2928, wherein heating the portion comprisesapplying electrical current to a conductor disposed in a conduit,wherein the conduit is disposed within the opening.
 2943. The method ofclaim 2928, wherein heating the portion comprises applying electricalcurrent to an insulated conductor disposed within the opening.
 2944. Themethod of claim 2928, wherein heating the portion comprises applyingelectrical current to at least one elongated member disposed within theopening.
 2945. The method of claim 2928, wherein heating the portioncomprises heating the oxidizing fluid in a heat exchanger disposedexternal to the formation such that providing the oxidizing fluid intothe opening comprises transferring heat from the heated oxidizing fluidto the portion.
 2946. The method of claim 2928, further comprisingremoving water from the formation prior to heating the portion. 2947.The method of claim 2928, further comprising controlling the temperatureof the formation to substantially inhibit production of oxides ofnitrogen during oxidation.
 2948. The method of claim 2928, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 2949.The method of claim 2928, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 2950. The method of claim 2928, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing is further disposed in cement.
 2951. The method of claim 2928,further comprising coupling an overburden casing to the opening, whereina packing material is disposed at a junction of the overburden casingand the opening.
 2952. The method of claim 2928, wherein the pyrolysiszone is substantially adjacent to the reaction.
 2953. A systemconfigured to heat an oil shale formation, comprising: an electricheater disposed in an opening in the formation, wherein the electricheater is configured to provide heat to at least a portion of theformation during use; an oxidizing fluid source; a conduit disposed inthe opening, wherein the conduit is configured to provide an oxidizingfluid from the oxidizing fluid source to a reaction zone in theformation during use, and wherein the oxidizing fluid is selected tooxidize at least some hydrocarbons at the reaction zone during use suchthat heat is generated at the reaction zone; and wherein the system isconfigured to allow heat to transfer substantially by conduction fromthe reaction zone to a pyrolysis zone of the formation during use. 2954.The system of claim 2953, wherein the oxidizing fluid is configured togenerate heat in the reaction zone such that the oxidizing fluid istransported through the reaction zone substantially by diffusion. 2955.The system of claim 2953, wherein the conduit comprises orifices, andwherein the orifices are configured to provide the oxidizing fluid intothe opening.
 2956. The system of claim 2953, wherein the conduitcomprises critical flow orifices, and wherein the critical flow orificesare configured to control a flow of the oxidizing fluid such that a rateof oxidation in the formation is controlled.
 2957. The system of claim2953, wherein the conduit is further configured to be cooled with theoxidizing fluid such that the conduit is not substantially heated byoxidation.
 2958. The system of claim 2953, wherein the conduit isfurther configured to remove an oxidation product.
 2959. The system ofclaim 2953, wherein the conduit is further configured to remove anoxidation product, such that the oxidation product transfers heat to theoxidizing fluid.
 2960. The system of claim 2953, wherein the conduit isfurther configured to remove an oxidation product, and wherein a flowrate of the oxidizing fluid in the conduit is approximately equal to aflow rate of the oxidation product in the conduit.
 2961. The system ofclaim 2953, wherein the conduit is further configured to remove anoxidation product, and wherein a pressure of the oxidizing fluid in theconduit and a pressure of the oxidation product in the conduit arecontrolled to reduce contamination of the oxidation product by theoxidizing fluid.
 2962. The system of claim 2953, wherein the conduit isfurther configured to remove an oxidation product, and wherein theoxidation product is substantially inhibited from flowing into portionsof the formation beyond the reaction zone.
 2963. The system of claim2953, wherein the oxidizing fluid is substantially inhibited fromflowing into portions of the formation beyond the reaction zone. 2964.The system of claim 2953, further comprising a center conduit disposedwithin the conduit, wherein the center conduit is configured to providethe oxidizing fluid into the opening during use, and wherein the conduitis further configured to remove an oxidation product during use. 2965.The system of claim 2953, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.2966. The system of claim 2953, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 2967. The system of claim 2953, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 2968. The system of claim2953, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 2969. The system of claim 2953, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 2970. The system ofclaim 2953, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 2971. The system of claim2953, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 2972. The system of claim 2953, wherein the system isfurther configured such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 2973. A system configurable to heatan oil shale formation, comprising: an electric heater configurable tobe disposed in an opening in the formation, wherein the electric heateris further configurable to provide heat to at least a portion of theformation during use, and wherein at least the portion is locatedsubstantially adjacent to the opening; a conduit configurable to bedisposed in the opening, wherein the conduit is further configurable toprovide an oxidizing fluid from an oxidizing fluid source to a reactionzone in the formation during use, and wherein the system is configurableto allow the oxidizing fluid to oxidize at least some hydrocarbons atthe reaction zone during use such that heat is generated at the reactionzone; and wherein the system is further configurable to allow heat totransfer substantially by conduction from the reaction zone to apyrolysis zone of the formation during use.
 2974. The system of claim2973, wherein the oxidizing fluid is configurable to generate heat inthe reaction zone such that the oxidizing fluid is transported throughthe reaction zone substantially by diffusion.
 2975. The system of claim2973, wherein the conduit comprises orifices, and wherein the orificesare configurable to provide the oxidizing fluid into the opening. 2976.The system of claim 2973, wherein the conduit comprises critical floworifices, and wherein the critical flow orifices are configurable tocontrol a flow of the oxidizing fluid such that a rate of oxidation inthe formation is controlled.
 2977. The system of claim 2973, wherein theconduit is further configurable to be cooled with the oxidizing fluidsuch that the conduit is not substantially heated by oxidation. 2978.The system of claim 2973, wherein the conduit is further configurable toremove an oxidation product.
 2979. The system of claim 2973, wherein theconduit is further configurable to remove an oxidation product such thatthe oxidation product transfers heat to the oxidizing fluid.
 2980. Thesystem of claim 2973, wherein the conduit is further configurable toremove an oxidation product, and wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 2981. The system of claim 2973,wherein the conduit is further configurable to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the conduitand a pressure of the oxidation product in the conduit are controlled toreduce contamination of the oxidation product by the oxidizing fluid.2982. The system of claim 2973, wherein the conduit is furtherconfigurable to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 2983. The system of claim 2973,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 2984. The system ofclaim 2973, further comprising a center conduit disposed within theconduit, wherein the center conduit is configurable to provide theoxidizing fluid into the opening during use, and wherein the conduit isfurther configurable to remove an oxidation product during use. 2985.The system of claim 2973, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.2986. The system of claim 2973, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 2987. The system of claim 2973, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 2988. The system of claim2973, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 2989. The system of claim 2973, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 2990. The system ofclaim 2973, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configurable to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 2991. The system of claim2973, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 2992. The system of claim 2973, wherein the system isfurther configurable such that transferred heat can pyrolyze at leastsome hydrocarbons in the pyrolysis zone.
 2993. The system of claim 2973,wherein the system is configured to heat an oil shale formation, andwherein the system comprises: an electric heater disposed in an openingin the formation, wherein the electric heater is configured to provideheat to at least a portion of the formation during use; an oxidizingfluid source; a conduit disposed in the opening, wherein the conduit isconfigured to provide an oxidizing fluid from the oxidizing fluid sourceto a reaction zone in the formation during use, and wherein theoxidizing fluid is selected to oxidize at least some hydrocarbons at thereaction zone during use such that heat is generated at the reactionzone; and wherein the system is configured to allow heat to transfersubstantially by conduction from the reaction zone to a pyrolysis zoneof the formation during use.
 2994. A system configured to heat an oilshale formation, comprising: a conductor disposed in a first conduit,wherein the first conduit is disposed in an opening in the formation,and wherein the conductor is configured to provide heat to at least aportion of the formation during use; an oxidizing fluid source; a secondconduit disposed in the opening, wherein the second conduit isconfigured to provide an oxidizing fluid from the oxidizing fluid sourceto a reaction zone in the formation during use, and wherein theoxidizing fluid is selected to oxidize at least some hydrocarbons at thereaction zone during use such that heat is generated at the reactionzone; and wherein the system is configured to allow heat to transfersubstantially by conduction from the reaction zone to a pyrolysis zoneof the formation during use.
 2995. The system of claim 2994, wherein theoxidizing fluid is configured to generate heat in the reaction zone suchthat the oxidizing fluid is transported through the reaction zonesubstantially by diffusion.
 2996. The system of claim 2994, wherein thesecond conduit comprises orifices, and wherein the orifices areconfigured to provide the oxidizing fluid into the opening.
 2997. Thesystem of claim 2994, wherein the second conduit comprises critical floworifices, and wherein the critical flow orifices are configured tocontrol a flow of the oxidizing fluid such that a rate of oxidation inthe formation is controlled.
 2998. The system of claim 2994, wherein thesecond conduit is further configured to be cooled with the oxidizingfluid to reduce heating of the second conduit by oxidation.
 2999. Thesystem of claim 2994, wherein the second conduit is further configuredto remove an oxidation product.
 3000. The system of claim 2994, whereinthe second conduit is further configured to remove an oxidation productsuch that the oxidation product transfers heat to the oxidizing fluid.3001. The system of claim 2994, wherein the second conduit is furtherconfigured to remove an oxidation product, and wherein a flow rate ofthe oxidizing fluid in the conduit is approximately equal to a flow rateof the oxidation product in the second conduit.
 3002. The system ofclaim 2994, wherein the second conduit is further configured to removean oxidation product, and wherein a pressure of the oxidizing fluid inthe second conduit and a pressure of the oxidation product in the secondconduit are controlled to reduce contamination of the oxidation productby the oxidizing fluid.
 3003. The system of claim 2994, wherein thesecond conduit is further configured to remove an oxidation product, andwherein the oxidation product is substantially inhibited from flowinginto portions of the formation beyond the reaction zone.
 3004. Thesystem of claim 2994, wherein the oxidizing fluid is substantiallyinhibited from flowing into portions of the formation beyond thereaction zone.
 3005. The system of claim 2994, further comprising acenter conduit disposed within the second conduit, wherein the centerconduit is configured to provide the oxidizing fluid into the openingduring use, and wherein the second conduit is further configured toremove an oxidation product during use.
 3006. The system of claim 2994,wherein the portion of the formation extends radially from the opening awidth of less than approximately 0.2 m.
 3007. The system of claim 2994,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation.3008. The system of claim 2994, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3009. The system of claim 2994, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3010. The system of claim 2994, furthercomprising an overburden casing coupled to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 3011. The system of claim 2994, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configured to substantiallyinhibit a flow of fluid between the opening and the overburden casingduring use.
 3012. The system of claim 2994, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material comprises cement.
 3013. Thesystem of claim 2994, wherein the system is further configured such thattransferred heat can pyrolyze at least some hydrocarbons in thepyrolysis zone.
 3014. A system configurable to heat an oil shaleformation, comprising: a conductor configurable to be disposed in afirst conduit, wherein the first conduit is configurable to be disposedin an opening in the formation, and wherein the conductor is furtherconfigurable to provide heat to at least a portion of the formationduring use; a second conduit configurable to be disposed in the opening,wherein the second conduit is further configurable to provide anoxidizing fluid from an oxidizing fluid source to a reaction zone in theformation during use, and wherein the system is configurable to allowthe oxidizing fluid to oxidize at least some hydrocarbons at thereaction zone during use such that heat is generated at the reactionzone; and wherein the system is further configurable to allow heat totransfer substantially by conduction from the reaction zone to apyrolysis zone of the formation during use.
 3015. The system of claim3014, wherein the oxidizing fluid is configurable to generate heat inthe reaction zone such that the oxidizing fluid is transported throughthe reaction zone substantially by diffusion.
 3016. The system of claim3014, wherein the second conduit comprises orifices, and wherein theorifices are configurable to provide the oxidizing fluid into theopening.
 3017. The system of claim 3014, wherein the second conduitcomprises critical flow orifices, and wherein the critical flow orificesare configurable to control a flow of the oxidizing fluid such that arate of oxidation in the formation is controlled.
 3018. The system ofclaim 3014, wherein the second conduit is further configurable to becooled with the oxidizing fluid to reduce heating of the second conduitby oxidation.
 3019. The system of claim 3014, wherein the second conduitis further configurable to remove an oxidation product.
 3020. The systemof claim 3014, wherein the second conduit is further configurable toremove an oxidation product such that the oxidation product transfersheat to the oxidizing fluid.
 3021. The system of claim 3014, wherein thesecond conduit is further configurable to remove an oxidation product,and wherein a flow rate of the oxidizing fluid in the conduit isapproximately equal to a flow rate of the oxidation product in thesecond conduit.
 3022. The system of claim 3014, wherein the secondconduit is further configurable to remove an oxidation product, andwherein a pressure of the oxidizing fluid in the second conduit and apressure of the oxidation product in the second conduit are controlledto reduce contamination of the oxidation product by the oxidizing fluid.3023. The system of claim 3014, wherein the second conduit is furtherconfigurable to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 3024. The system of claim 3014,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 3025. The system ofclaim 3014, further comprising a center conduit disposed within thesecond conduit, wherein the center conduit is configurable to providethe oxidizing fluid into the opening during use, and wherein the secondconduit is further configurable to remove an oxidation product duringuse.
 3026. The system of claim 3014, wherein the portion of theformation extends radially from the opening a width of less thanapproximately 0.2 m.
 3027. The system of claim 3014, further comprisingan overburden casing coupled to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 3028. The systemof claim 3014, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 3029.The system of claim 3014, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3030. The system of claim 3014, furthercomprising an overburden casing coupled to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 3031. The system of claim 3014, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 3032. The system of claim 3014, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.3033. The system of claim 3014, wherein the system is furtherconfigurable such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 3034. The system of claim 3014,wherein the system is configured to heat an oil shale formation, andwherein the system comprises: a conductor disposed in a first conduit,wherein the first conduit is disposed in an opening in the formation,and wherein the conductor is configured to provide heat to at least aportion of the formation during use; an oxidizing fluid source; a secondconduit disposed in the opening, wherein the second conduit isconfigured to provide an oxidizing fluid from the oxidizing fluid sourceto a reaction zone in the formation during use, and wherein theoxidizing fluid is selected to oxidize at least some hydrocarbons at thereaction zone during use such that heat is generated at the reactionzone; and wherein the system is configured to allow heat to transfersubstantially by conduction from the reaction zone to a pyrolysis zoneof the formation during use.
 3035. An in situ method for heating an oilshale formation, comprising: heating a portion of the formation to atemperature sufficient to support reaction of hydrocarbons within theportion of the formation with an oxidizing fluid, wherein heatingcomprises applying an electrical current to a conductor disposed in afirst conduit to provide heat to the portion, and wherein the firstconduit is disposed within the opening; providing the oxidizing fluid toa reaction zone in the formation; allowing the oxidizing fluid to reactwith at least a portion of the hydrocarbons at the reaction zone togenerate heat at the reaction zone; and transferring the generated heatsubstantially by conduction from the reaction zone to a pyrolysis zonein the formation.
 3036. The method of claim 3035, further comprisingtransporting the oxidizing fluid through the reaction zone by diffusion.3037. The method of claim 3035, further comprising directing at least aportion of the oxidizing fluid into the opening through orifices of asecond conduit disposed in the opening.
 3038. The method of claim 3035,further comprising controlling a flow of the oxidizing fluid withcritical flow orifices of a second conduit disposed in the opening suchthat a rate of oxidation is controlled.
 3039. The method of claim 3035,further comprising increasing a flow of the oxidizing fluid in theopening to accommodate an increase in a volume of the reaction zone suchthat a rate of oxidation is substantially constant over time within thereaction zone.
 3040. The method of claim 3035, wherein a second conduitis disposed in the opening, the method further comprising cooling thesecond conduit with the oxidizing fluid to reduce heating of the secondconduit by oxidation.
 3041. The method of claim 3035, wherein a secondconduit is disposed within the opening, the method further comprisingremoving an oxidation product from the formation through the secondconduit.
 3042. The method of claim 3035, wherein a second conduit isdisposed within the opening, the method further comprising removing anoxidation product from the formation through the second conduit andtransferring heat from the oxidation product in the conduit to theoxidizing fluid in the second conduit.
 3043. The method of claim 3035,wherein a second conduit is disposed within the opening, the methodfurther comprising removing an oxidation product from the formationthrough the second conduit, wherein a flow rate of the oxidizing fluidin the second conduit is approximately equal to a flow rate of theoxidation product in the second conduit.
 3044. The method of claim 3035,wherein a second conduit is disposed within the opening, the methodfurther comprising removing an oxidation product from the formationthrough the second conduit and controlling a pressure between theoxidizing fluid and the oxidation product in the second conduit toreduce contamination of the oxidation product by the oxidizing fluid.3045. The method of claim 3035, wherein a second conduit is disposedwithin the opening, the method further comprising removing an oxidationproduct from the formation through the conduit and substantiallyinhibiting the oxidation product from flowing into portions of theformation beyond the reaction zone.
 3046. The method of claim 3035,further comprising substantially inhibiting the oxidizing fluid fromflowing into portions of the formation beyond the reaction zone. 3047.The method of claim 3035, wherein a center conduit is disposed within anouter conduit, and wherein the outer conduit is disposed within theopening, the method further comprising providing the oxidizing fluidinto the opening through the center conduit and removing an oxidationproduct through the outer conduit.
 3048. The method of claim 3035,wherein the portion of the formation extends radially from the opening awidth of less than approximately 0.2 m.
 3049. The method of claim 3035,further comprising removing water from the formation prior to heatingthe portion.
 3050. The method of claim 3035, further comprisingcontrolling the temperature of the formation to substantially inhibitproduction of oxides of nitrogen during oxidation.
 3051. The method ofclaim 3035, further comprising coupling an overburden casing to theopening, wherein the overburden casing is disposed in an overburden ofthe formation.
 3052. The method of claim 3035, further comprisingcoupling an overburden casing to the opening, wherein the overburdencasing is disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3053. The method of claim 3035,further comprising coupling an overburden casing to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3054. Themethod of claim 3035, further comprising coupling an overburden casingto the opening, wherein a packing material is disposed at a junction ofthe overburden casing and the opening.
 3055. A system configured to heatan oil shale formation, comprising: an insulated conductor disposed inan opening in the formation, wherein the insulated conductor isconfigured to provide heat to at least a portion of the formation duringuse; an oxidizing fluid source; a conduit disposed in the opening,wherein the conduit is configured to provide an oxidizing fluid from theoxidizing fluid source to a reaction zone in the formation during use,and wherein the oxidizing fluid is selected to oxidize at least somehydrocarbons at the reaction zone during use such that heat is generatedat the reaction zone; and wherein the system is configured to allow heatto transfer substantially by conduction from the reaction zone to apyrolysis zone of the formation during use.
 3056. The system of claim3055, wherein the oxidizing fluid is configured to generate heat in thereaction zone such that the oxidizing fluid is transported through thereaction zone substantially by diffusion.
 3057. The system of claim3055, wherein the conduit comprises orifices, and wherein the orificesare configured to provide the oxidizing fluid into the opening. 3058.The system of claim 3055, wherein the conduit comprises critical floworifices, and wherein the critical flow orifices are configured tocontrol a flow of the oxidizing fluid such that a rate of oxidation inthe formation is controlled.
 3059. The system of claim 3055, wherein theconduit is configured to be cooled with the oxidizing fluid such thatthe conduit is not substantially heated by oxidation.
 3060. The systemof claim 3055, wherein the conduit is further configured to remove anoxidation product.
 3061. The system of claim 3055, wherein the conduitis further configured to remove an oxidation product, and wherein theconduit is further configured such that the oxidation product transferssubstantial heat to the oxidizing fluid.
 3062. The system of claim 3055,wherein the conduit is further configured to remove an oxidationproduct, and wherein a flow rate of the oxidizing fluid in the conduitis approximately equal to a flow rate of the oxidation product in theconduit.
 3063. The system of claim 3055, wherein the conduit is furtherconfigured to remove an oxidation product, and wherein a pressure of theoxidizing fluid in the second conduit and a pressure of the oxidationproduct in the conduit are controlled to reduce contamination of theoxidation product by the oxidizing fluid.
 3064. The system of claim3055, wherein the conduit is further configured to remove an oxidationproduct, and wherein the oxidation product is substantially inhibitedfrom flowing into portions of the formation beyond the reaction zone.3065. The system of claim 3055, wherein the oxidizing fluid issubstantially inhibited from flowing into portions of the formationbeyond the reaction zone.
 3066. The system of claim 3055, furthercomprising a center conduit disposed within the conduit, wherein thecenter conduit is configured to provide the oxidizing fluid into theopening during use, and wherein the conduit is further configured toremove an oxidation product during use.
 3067. The system of claim 3055,wherein the portion of the formation extends radially from the opening awidth of less than approximately 0.2 m.
 3068. The system of claim 3055,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation.3069. The system of claim 3055, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3070. The system of claim 3055, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3071. The system of claim 3055, furthercomprising an overburden casing coupled to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 3072. The system of claim 3055, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configured to substantiallyinhibit a flow of fluid between the opening and the overburden casingduring use.
 3073. The system of claim 3055, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material comprises cement.
 3074. Thesystem of claim 3055, wherein the system is further configured such thattransferred heat can pyrolyze at least some hydrocarbons in thepyrolysis zone.
 3075. A system configurable to heat an oil shaleformation, comprising: an insulated conductor configurable to bedisposed in an opening in the formation, wherein the insulated conductoris further configurable to provide heat to at least a portion of theformation during use; a conduit configurable to be disposed in theopening, wherein the conduit is further configurable to provide anoxidizing fluid from an oxidizing fluid source to a reaction zone in theformation during use, and wherein the system is configurable to allowthe oxidizing fluid to oxidize at least some hydrocarbons at thereaction zone during use such that heat is generated at the reactionzone; and wherein the system is further configurable to allow heat totransfer substantially by conduction from the reaction zone to apyrolysis zone of the formation during use.
 3076. The system of claim3075, wherein the oxidizing fluid is configurable to generate heat inthe reaction zone such that the oxidizing fluid is transported throughthe reaction zone substantially by diffusion.
 3077. The system of claim3075, wherein the conduit comprises orifices, and wherein the orificesare configurable to provide the oxidizing fluid into the opening. 3078.The system of claim 3075, wherein the conduit comprises critical floworifices, and wherein the critical flow orifices are configurable tocontrol a flow of the oxidizing fluid such that a rate of oxidation inthe formation is controlled.
 3079. The system of claim 3075, wherein theconduit is further configurable to be cooled with the oxidizing fluidsuch that the conduit is not substantially heated by oxidation. 3080.The system of claim 3075, wherein the conduit is further configurable toremove an oxidation product.
 3081. The system of claim 3075, wherein theconduit is further configurable to remove an oxidation product, suchthat the oxidation product transfers heat to the oxidizing fluid. 3082.The system of claim 3075, wherein the conduit is further configurable toremove an oxidation product, and wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 3083. The system of claim 3075,wherein the conduit is further configurable to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the conduitand a pressure of the oxidation product in the conduit are controlled toreduce contamination of the oxidation product by the oxidizing fluid.3084. The system of claim 3075, wherein the conduit is furtherconfigurable to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 3085. The system of claim 3075,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 3086. The system ofclaim 3075, further comprising a center conduit disposed within theconduit, wherein the center conduit is configurable to provide theoxidizing fluid into the opening during use, and wherein the conduit isfurther configurable to remove an oxidation product during use. 3087.The system of claim 3075, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.3088. The system of claim 3075, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3089. The system of claim 3075, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3090. The system of claim3075, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3091. The system of claim 3075, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 3092. The system ofclaim 3075, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configurable to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3093. The system of claim3075, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3094. The system of claim 3075, wherein the system isfurther configurable such that transferred heat can pyrolyze at leastsome hydrocarbons in the pyrolysis zone.
 3095. The system of claim 3075,wherein the system is configured to heat an oil shale formation, andwherein the system comprises: an insulated conductor disposed in anopening in the formation, wherein the insulated conductor is configuredto provide heat to at least a portion of the formation during use; anoxidizing fluid source; a conduit disposed in the opening, wherein theconduit is configured to provide an oxidizing fluid from the oxidizingfluid source to a reaction zone in the formation during use, and whereinthe oxidizing fluid is selected to oxidize at least some hydrocarbons atthe reaction zone during use such that heat is generated at the reactionzone; and wherein the system is configured to allow heat to transfersubstantially by conduction from the reaction zone to a pyrolysis zoneof the formation during use.
 3096. An in situ method for heating an oilshale formation, comprising: heating a portion of the formation to atemperature sufficient to support reaction of hydrocarbons within theportion of the formation with an oxidizing fluid, wherein heatingcomprises applying an electrical current to an insulated conductor toprovide heat to the portion, and wherein the insulated conductor isdisposed within the opening; providing the oxidizing fluid to a reactionzone in the formation; allowing the oxidizing fluid to react with atleast a portion of the hydrocarbons at the reaction zone to generateheat at the reaction zone; and transferring the generated heatsubstantially by conduction from the reaction zone to a pyrolysis zonein the formation.
 3097. The method of claim 3096, further comprisingtransporting the oxidizing fluid through the reaction zone by diffusion.3098. The method of claim 3096, further comprising directing at least aportion of the oxidizing fluid into the opening through orifices of aconduit disposed in the opening.
 3099. The method of claim 3096, furthercomprising controlling a flow of the oxidizing fluid with critical floworifices of a conduit disposed in the opening such that a rate ofoxidation is controlled.
 3100. The method of claim 3096, furthercomprising increasing a flow of the oxidizing fluid in the opening toaccommodate an increase in a volume of the reaction zone such that arate of oxidation is substantially constant over time within thereaction zone.
 3101. The method of claim 3096, wherein a conduit isdisposed in the opening, the method further comprising cooling theconduit with the oxidizing fluid to reduce heating of the conduit byoxidation.
 3102. The method of claim 3096, wherein a conduit is disposedwithin the opening, the method further comprising removing an oxidationproduct from the formation through the conduit.
 3103. The method ofclaim 3096, wherein a conduit is disposed within the opening, the methodfurther comprising removing an oxidation product from the formationthrough the conduit and transferring heat from the oxidation product inthe conduit to the oxidizing fluid in the conduit.
 3104. The method ofclaim 3096, wherein a conduit is disposed within the opening, the methodfurther comprising removing an oxidation product from the formationthrough the conduit, wherein a flow rate of the oxidizing fluid in theconduit is approximately equal to a flow rate of the oxidation productin the conduit.
 3105. The method of claim 3096, wherein a conduit isdisposed within the opening, the method further comprising removing anoxidation product from the formation through the conduit and controllinga pressure between the oxidizing fluid and the oxidation product in theconduit to reduce contamination of the oxidation product by theoxidizing fluid.
 3106. The method of claim 3096, wherein a conduit isdisposed within the opening, the method further comprising removing anoxidation product from the formation through the conduit andsubstantially inhibiting the oxidation product from flowing intoportions of the formation beyond the reaction zone.
 3107. The method ofclaim 3096, further comprising substantially inhibiting the oxidizingfluid from flowing into portions of the formation beyond the reactionzone.
 3108. The method of claim 3096, wherein a center conduit isdisposed within an outer conduit, and wherein the outer conduit isdisposed within the opening, the method further comprising providing theoxidizing fluid into the opening through the center conduit and removingan oxidation product through the outer conduit.
 3109. The method ofclaim 3096, wherein the portion of the formation extends radially fromthe opening a width of less than approximately 0.2 m.
 3110. The methodof claim 3096, further comprising removing water from the formationprior to heating the portion.
 3111. The method of claim 3096, furthercomprising controlling the temperature of the formation to substantiallyinhibit production of oxides of nitrogen during oxidation.
 3112. Themethod of claim 3096, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3113. The method of claim 3096, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3114. The method of claim3096, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3115. The method of claim 3096, further comprising coupling anoverburden casing to the opening, wherein a packing material is disposedat a junction of the overburden casing and the opening.
 3116. The methodof claim 3096, wherein the pyrolysis zone is substantially adjacent tothe reaction zone.
 3117. An in situ method for heating an oil shaleformation, comprising: heating a portion of the formation to atemperature sufficient to support reaction of hydrocarbons within theportion of the formation with an oxidizing fluid, wherein the portion islocated substantially adjacent to an opening in the formation, whereinheating comprises applying an electrical current to an insulatedconductor to provide heat to the portion, wherein the insulatedconductor is coupled to a conduit, wherein the conduit comprisescritical flow orifices, and wherein the conduit is disposed within theopening; providing the oxidizing fluid to a reaction zone in theformation; allowing the oxidizing fluid to react with at least a portionof the hydrocarbons at the reaction zone to generate heat at thereaction zone; and transferring the generated heat substantially byconduction from the reaction zone to a pyrolysis zone in the formation.3118. The method of claim 3117, further comprising transporting theoxidizing fluid through the reaction zone by diffusion.
 3119. The methodof claim 3117, further comprising controlling a flow of the oxidizingfluid with the critical flow orifices such that a rate of oxidation iscontrolled.
 3120. The method of claim 3117, further comprisingincreasing a flow of the oxidizing fluid in the opening to accommodatean increase in a volume of the reaction zone such that a rate ofoxidation is substantially constant over time within the reaction zone.3121. The method of claim 3117, further comprising cooling the conduitwith the oxidizing fluid to reduce heating of the conduit by oxidation.3122. The method of claim 3117, further comprising removing an oxidationproduct from the formation through the conduit.
 3123. The method ofclaim 3117, further comprising removing an oxidation product from theformation through the conduit and transferring heat from the oxidationproduct in the conduit to the oxidizing fluid in the conduit.
 3124. Themethod of claim 3117, further comprising removing an oxidation productfrom the formation through the conduit, wherein a flow rate of theoxidizing fluid in the conduit is approximately equal to a flow rate ofthe oxidation product in the conduit.
 3125. The method of claim 3117,further comprising removing an oxidation product from the formationthrough the conduit and controlling a pressure between the oxidizingfluid and the oxidation product in the conduit to reduce contaminationof the oxidation product by the oxidizing fluid.
 3126. The method ofclaim 3117, further comprising removing an oxidation product from theformation through the conduit and substantially inhibiting the oxidationproduct from flowing into portions of the formation beyond the reactionzone.
 3127. The method of claim 3117, further comprising substantiallyinhibiting the oxidizing fluid from flowing into portions of theformation beyond the reaction zone.
 3128. The method of claim 3117,wherein a center conduit is disposed within the conduit, the methodfurther comprising providing the oxidizing fluid into the openingthrough the center conduit and removing an oxidation product through theconduit.
 3129. The method of claim 3117, wherein the portion of theformation extends radially from the opening a width of less thanapproximately 0.2 m.
 3130. The method of claim 3117, further comprisingremoving water from the formation prior to heating the portion. 3131.The method of claim 3117, further comprising controlling the temperatureof the formation to substantially inhibit production of oxides ofnitrogen during oxidation.
 3132. The method of claim 3117, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3133.The method of claim 3117, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3134. The method of claim 3117, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing is further disposed in cement.
 3135. The method of claim 3117,further comprising coupling an overburden casing to the opening, whereina packing material is disposed at a junction of the overburden casingand the opening.
 3136. The method of claim 3117, wherein the pyrolysiszone is substantially adjacent to the reaction zone.
 3137. A systemconfigured to heat an oil shale formation, comprising: at least oneelongated member disposed in an opening in the formation, wherein atleast the one elongated member is configured to provide heat to at leasta portion of the formation during use; an oxidizing fluid source; aconduit disposed in the opening, wherein the conduit is configured toprovide an oxidizing fluid from the oxidizing fluid source to a reactionzone in the formation during use, and wherein the oxidizing fluid isselected to oxidize at least some hydrocarbons at the reaction zoneduring use such that heat is generated at the reaction zone; and whereinthe system is configured to allow heat to transfer substantially byconduction from the reaction zone to a pyrolysis zone of the formationduring use.
 3138. The system of claim 3137, wherein the oxidizing fluidis configured to generate heat in the reaction zone such that theoxidizing fluid is transported through the reaction zone substantiallyby diffusion.
 3139. The system of claim 3137, wherein the conduitcomprises orifices, and wherein the orifices are configured to providethe oxidizing fluid into the opening.
 3140. The system of claim 3137,wherein the conduit comprises critical flow orifices, and wherein thecritical flow orifices are configured to control a flow of the oxidizingfluid such that a rate of oxidation in the formation is controlled.3141. The system of claim 3137, wherein the conduit is furtherconfigured to be cooled with the oxidizing fluid such that the conduitis not substantially heated by oxidation.
 3142. The system of claim3137, wherein the conduit is further configured to remove an oxidationproduct.
 3143. The system of claim 3137, wherein the conduit is furtherconfigured to remove an oxidation product such that the oxidationproduct transfers heat to the oxidizing fluid.
 3144. The system of claim3137, wherein the conduit is further configured to remove an oxidationproduct, and wherein a flow rate of the oxidizing fluid in the conduitis approximately equal to a flow rate of the oxidation product in theconduit.
 3145. The system of claim 3137, wherein the conduit is furtherconfigured to remove an oxidation product, and wherein a pressure of theoxidizing fluid in the conduit and a pressure of the oxidation productin the conduit are controlled to reduce contamination of the oxidationproduct by the oxidizing fluid.
 3146. The system of claim 3137, whereinthe conduit is further configured to remove an oxidation product, andwherein the oxidation product is substantially inhibited from flowinginto portions of the formation beyond the reaction zone.
 3147. Thesystem of claim 3137, wherein the oxidizing fluid is substantiallyinhibited from flowing into portions of the formation beyond thereaction zone.
 3148. The system of claim 3137, further comprising acenter conduit disposed within the conduit, wherein the center conduitis configured to provide the oxidizing fluid into the opening duringuse, and wherein the conduit is further configured to remove anoxidation product during use.
 3149. The system of claim 3137, whereinthe portion of the formation extends radially from the opening a widthof less than approximately 0.2 m.
 3150. The system of claim 3137,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation.3151. The system of claim 3137, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3152. The system of claim 3137, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3153. The system of claim 3137, furthercomprising an overburden casing coupled to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 3154. The system of claim 3137, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configured to substantiallyinhibit a flow of fluid between the opening and the overburden casingduring use.
 3155. The system of claim 3137, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material comprises cement.
 3156. Thesystem of claim 3137, wherein the system is further configured such thattransferred heat can pyrolyze at least some hydrocarbons in thepyrolysis zone.
 3157. A system configurable to heat an oil shaleformation, comprising: at least one elongated member configurable to bedisposed in an opening in the formation, wherein at least the oneelongated member is further configurable to provide heat to at least aportion of the formation during use; a conduit configurable to bedisposed in the opening, wherein the conduit is further configurable toprovide an oxidizing fluid from the oxidizing fluid source to a reactionzone in the formation during use, and wherein the system is configurableto allow the oxidizing fluid to oxidize at least some hydrocarbons atthe reaction zone during use such that heat is generated at the reactionzone; and wherein the system is further configurable to allow heat totransfer substantially by conduction from the reaction zone to apyrolysis zone of the formation during use.
 3158. The system of claim3157, wherein the oxidizing fluid is configurable to generate heat inthe reaction zone such that the oxidizing fluid is transported throughthe reaction zone substantially by diffusion.
 3159. The system of claim3157, wherein the conduit comprises orifices, and wherein the orificesare configurable to provide the oxidizing fluid into the opening. 3160.The system of claim 3157, wherein the conduit comprises critical floworifices, and wherein the critical flow orifices are configurable tocontrol a flow of the oxidizing fluid such that a rate of oxidation inthe formation is controlled.
 3161. The system of claim 3157, wherein theconduit is further configurable to be cooled with the oxidizing fluidsuch that the conduit is not substantially heated by oxidation. 3162.The system of claim 3157, wherein the conduit is further configurable toremove an oxidation product.
 3163. The system of claim 3157, wherein theconduit is further configurable to remove an oxidation product such thatthe oxidation product transfers heat to the oxidizing fluid.
 3164. Thesystem of claim 3157, wherein the conduit is further configurable toremove an oxidation product, and wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 3165. The system of claim 3157,wherein the conduit is further configurable to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the conduitand a pressure of the oxidation product in the conduit are controlled toreduce contamination of the oxidation product by the oxidizing fluid.3166. The system of claim 3157, wherein the conduit is furtherconfigurable to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 3167. The system of claim 3157,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 3168. The system ofclaim 3157, further comprising a center conduit disposed within theconduit, wherein the center conduit is configurable to provide theoxidizing fluid into the opening during use, and wherein the conduit isfurther configurable to remove an oxidation product during use. 3169.The system of claim 3157, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.3170. The system of claim 3157, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3171. The system of claim 3157, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3172. The system of claim3157, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3173. The system of claim 3157, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 3174. The system ofclaim 3157, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configurable to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3175. The system of claim3157, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3176. The system of claim 3157, wherein the system isfurther configurable such that transferred heat can pyrolyze at leastsome hydrocarbons in the pyrolysis zone.
 3177. The system of claim 3157,wherein the system is configured to heat an oil shale formation, andwherein the system comprises: at least one elongated member disposed inan opening in the formation, wherein at least the one elongated memberis configured to provide heat to at least a portion of the formationduring use; an oxidizing fluid source; a conduit disposed in theopening, wherein the conduit is configured to provide an oxidizing fluidfrom the oxidizing fluid source to a reaction zone in the formationduring use, and wherein the oxidizing fluid is selected to oxidize atleast some hydrocarbons at the reaction zone during use such that heatis generated at the reaction zone; and wherein the system is configuredto allow heat to transfer substantially by conduction from the reactionzone to a pyrolysis zone of the formation during use.
 3178. An in situmethod for heating an oil shale formation, comprising: heating a portionof the formation to a temperature sufficient to support reaction ofhydrocarbons within the portion of the formation with an oxidizingfluid, wherein heating comprises applying an electrical current to atleast one elongated member to provide heat to the portion, and whereinat least the one elongated member is disposed within the opening;providing the oxidizing fluid to a reaction zone in the formation;allowing the oxidizing fluid to react with at least a portion of thehydrocarbons at the reaction zone to generate heat at the reaction zone;and transferring the generated heat substantially by conduction from thereaction zone to a pyrolysis zone in the formation.
 3179. The method ofclaim 3178, further comprising transporting the oxidizing fluid throughthe reaction zone by diffusion.
 3180. The method of claim 3178, furthercomprising directing at least a portion of the oxidizing fluid into theopening through orifices of a conduit disposed in the opening.
 3181. Themethod of claim 3178, further comprising controlling a flow of theoxidizing fluid with critical flow orifices of a conduit disposed in theopening such that a rate of oxidation is controlled.
 3182. The method ofclaim 3178, further comprising increasing a flow of the oxidizing fluidin the opening to accommodate an increase in a volume of the reactionzone such that a rate of oxidation is substantially constant over timewithin the reaction zone.
 3183. The method of claim 3178, wherein aconduit is disposed in the opening, the method further comprisingcooling the conduit with the oxidizing fluid to reduce heating of theconduit by oxidation.
 3184. The method of claim 3178, wherein a conduitis disposed within the opening, the method further comprising removingan oxidation product from the formation through the conduit.
 3185. Themethod of claim 3178, wherein a conduit is disposed within the opening,the method further comprising removing an oxidation product from theformation through the conduit and transferring heat from the oxidationproduct in the conduit to the oxidizing fluid in the conduit.
 3186. Themethod of claim 3178, wherein a conduit is disposed within the opening,the method further comprising removing an oxidation product from theformation through the conduit, wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 3187. The method of claim 3178,wherein a conduit is disposed within the opening, the method furthercomprising removing an oxidation product from the formation through theconduit and controlling a pressure between the oxidizing fluid and theoxidation product in the conduit to reduce contamination of theoxidation product by the oxidizing fluid.
 3188. The method of claim3178, wherein a conduit is disposed within the opening, the methodfurther comprising removing an oxidation product from the formationthrough the conduit and substantially inhibiting the oxidation productfrom flowing into portions of the formation beyond the reaction zone.3189. The method of claim 3178, further comprising substantiallyinhibiting the oxidizing fluid from flowing into portions of theformation beyond the reaction zone.
 3190. The method of claim 3178,wherein a center conduit is disposed within an outer conduit, andwherein the outer conduit is disposed within the opening, the methodfurther comprising providing the oxidizing fluid into the openingthrough the center conduit and removing an oxidation product through theouter conduit.
 3191. The method of claim 3178, wherein the portion ofthe formation extends radially from the opening a width of less thanapproximately 0.2 m.
 3192. The method of claim 3178, further comprisingremoving water from the formation prior to heating the portion. 3193.The method of claim 3178, further comprising controlling the temperatureof the formation to substantially inhibit production of oxides ofnitrogen during oxidation.
 3194. The method of claim 3178, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3195.The method of claim 3178, farther comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3196. The method of claim 3178, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing is further disposed in cement.
 3197. The method of claim 3178,further comprising coupling an overburden casing to the opening, whereina packing material is disposed at a junction of the overburden casingand the opening.
 3198. The method of claim 3178, wherein the pyrolysiszone is substantially adjacent to the reaction zone.
 3199. A systemconfigured to heat an oil shale formation, comprising: a heat exchangerdisposed external to the formation, wherein the heat exchanger isconfigured to heat an oxidizing fluid during use; a conduit disposed inthe opening, wherein the conduit is configured to provide the heatedoxidizing fluid from the heat exchanger to at least a portion of theformation during use, wherein the system is configured to allow heat totransfer from the heated oxidizing fluid to at least the portion of theformation during use, and wherein the oxidizing fluid is selected tooxidize at least some hydrocarbons at a reaction zone in the formationduring use such that heat is generated at the reaction zone; and whereinthe system is configured to allow heat to transfer substantially byconduction from the reaction zone to a pyrolysis zone of the formationduring use.
 3200. The system of claim 3199, wherein the oxidizing fluidis configured to generate heat in the reaction zone such that theoxidizing fluid is transported through the reaction zone substantiallyby diffusion.
 3201. The system of claim 3199, wherein the conduitcomprises orifices, and wherein the orifices are configured to providethe oxidizing fluid into the opening.
 3202. The system of claim 3199,wherein the conduit comprises critical flow orifices, and wherein thecritical flow orifices are configured to control a flow of the oxidizingfluid such that a rate of oxidation in the formation is controlled.3203. The system of claim 3199, wherein the conduit is furtherconfigured to be cooled with the oxidizing fluid such that the conduitis not substantially heated by oxidation.
 3204. The system of claim3199, wherein the conduit is further configured to remove an oxidationproduct.
 3205. The system of claim 3199, wherein the conduit is furtherconfigured to remove an oxidation product, such that the oxidationproduct transfers heat to the oxidizing fluid.
 3206. The system of claim3199, wherein the conduit is further configured to remove an oxidationproduct, and wherein a flow rate of the oxidizing fluid in the conduitis approximately equal to a flow rate of the oxidation product in theconduit.
 3207. The system of claim 3199, wherein the conduit is furtherconfigured to remove an oxidation product, and wherein a pressure of theoxidizing fluid in the conduit and a pressure of the oxidation productin the conduit are controlled to reduce contamination of the oxidationproduct by the oxidizing fluid.
 3208. The system of claim 3199, whereinthe conduit is further configured to remove an oxidation product, andwherein the oxidation product is substantially inhibited from flowinginto portions of the formation beyond the reaction zone.
 3209. Thesystem of claim 3199, wherein the oxidizing fluid is substantiallyinhibited from flowing into portions of the formation beyond thereaction zone.
 3210. The system of claim 3199, further comprising acenter conduit disposed within the conduit, wherein the center conduitis configured to provide the oxidizing fluid into the opening duringuse, and wherein the conduit is further configured to remove anoxidation product during use.
 3211. The system of claim 3199, whereinthe portion of the formation extends radially from the opening a widthof less than approximately 0.2 m.
 3212. The system of claim 3199,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation.3213. The system of claim 3199, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3214. The system of claim 3199, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3215. The system of claim 3199, furthercomprising an overburden casing coupled to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 3216. The system of claim 3199, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configured to substantiallyinhibit a flow of fluid between the opening and the overburden casingduring use.
 3217. The system of claim 3199, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material comprises cement.
 3218. Asystem configurable to heat an oil shale formation, comprising: a heatexchanger configurable to be disposed external to the formation, whereinthe heat exchanger is further configurable to heat an oxidizing fluidduring use; a conduit configurable to be disposed in the opening,wherein the conduit is further configurable to provide the heatedoxidizing fluid from the heat exchanger to at least a portion of theformation during use, wherein the system is configurable to allow heatto transfer from the heated oxidizing fluid to at least the portion ofthe formation during use, and wherein the system is further configurableto allow the oxidizing fluid to oxidize at least some hydrocarbons at areaction zone in the formation during use such that heat is generated atthe reaction zone; and wherein the system is further configurable toallow heat to transfer substantially by conduction from the reactionzone to a pyrolysis zone of the formation during use.
 3219. The systemof claim 3218, wherein the oxidizing fluid is configurable to generateheat in the reaction zone such that the oxidizing fluid is transportedthrough the reaction zone substantially by diffusion.
 3220. The systemof claim 3218, wherein the conduit comprises orifices, and wherein theorifices are configurable to provide the oxidizing fluid into theopening.
 3221. The system of claim 3218, wherein the conduit comprisescritical flow orifices, and wherein the critical flow orifices areconfigurable to control a flow of the oxidizing fluid such that a rateof oxidation in the formation is controlled.
 3222. The system of claim3218, wherein the conduit is further configurable to be cooled with theoxidizing fluid such that the conduit is not substantially heated byoxidation.
 3223. The system of claim 3218, wherein the conduit isfurther configurable to remove an oxidation product.
 3224. The system ofclaim 3218, wherein the conduit is further configurable to remove anoxidation product such that the oxidation product transfers heat to theoxidizing fluid.
 3225. The system of claim 3218, wherein the conduit isfurther configurable to remove an oxidation product, and wherein a flowrate of the oxidizing fluid in the conduit is approximately equal to aflow rate of the oxidation product in the conduit.
 3226. The system ofclaim 3218, wherein the conduit is further configurable to remove anoxidation product, and wherein a pressure of the oxidizing fluid in theconduit and a pressure of the oxidation product in the conduit arecontrolled to reduce contamination of the oxidation product by theoxidizing fluid.
 3227. The system of claim 3218, wherein the conduit isfurther configurable to remove an oxidation product, and wherein theoxidation product is substantially inhibited from flowing into portionsof the formation beyond the reaction zone.
 3228. The system of claim3218, wherein the oxidizing fluid is substantially inhibited fromflowing into portions of the formation beyond the reaction zone. 3229.The system of claim 3218, further comprising a center conduit disposedwithin the conduit, wherein the center conduit is configurable toprovide the oxidizing fluid into the opening during use, and wherein thesecond conduit is further configurable to remove an oxidation productduring use.
 3230. The system of claim 3218, wherein the portion of theformation extends radially from the opening a width of less thanapproximately 0.2 m.
 3231. The system of claim 3218, further comprisingan overburden casing coupled to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 3232. The systemof claim 3218, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 3233.The system of claim 3218, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3234. The system of claim 3218, furthercomprising an overburden casing coupled to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 3235. The system of claim 3218, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 3236. The system of claim 3218, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.3237. The system of claim 3218, wherein the system is configured to heatan oil shale formation, and wherein the system comprises: a heatexchanger disposed external to the formation, wherein the heat exchangeris configured to heat an oxidizing fluid during use; a conduit disposedin the opening, wherein the conduit is configured to provide the heatedoxidizing fluid from the heat exchanger to at least a portion of theformation during use, wherein the system is configured to allow heat totransfer from the heated oxidizing fluid to at least the portion of theformation during use, and wherein the oxidizing fluid is selected tooxidize at least some hydrocarbons at a reaction zone in the formationduring use such that heat is generated at the reaction zone; and whereinthe system is configured to allow heat to transfer substantially byconduction from the reaction zone to a pyrolysis zone of the formationduring use.
 3238. An in situ method for heating an oil shale formation,comprising: heating a portion of the formation to a temperaturesufficient to support reaction of hydrocarbons within the portion of theformation with an oxidizing fluid, wherein heating comprises: heatingthe oxidizing fluid with a heat exchanger, wherein the heat exchanger isdisposed external to the formation; providing the heated oxidizing fluidfrom the heat exchanger to the portion of the formation; allowing heatto transfer from the heated oxidizing fluid to the portion of theformation; providing the oxidizing fluid to a reaction zone in theformation; allowing the oxidizing fluid to react with at least a portionof the hydrocarbons at the reaction zone to generate heat at thereaction zone; and transferring the generated heat substantially byconduction from the reaction zone to a pyrolysis zone in the formation.3239. The method of claim 3238, further comprising transporting theoxidizing fluid through the reaction zone by diffusion.
 3240. The methodof claim 3238, further comprising directing at least a portion of theoxidizing fluid into the opening through orifices of a conduit disposedin the opening.
 3241. The method of claim 3238, further comprisingcontrolling a flow of the oxidizing fluid with critical flow orifices ofa conduit disposed in the opening such that a rate of oxidation iscontrolled.
 3242. The method of claim 3238, further comprisingincreasing a flow of the oxidizing fluid in the opening to accommodatean increase in a volume of the reaction zone such that a rate ofoxidation is substantially constant over time within the reaction zone.3243. The method of claim 3238, wherein a conduit is disposed in theopening, the method further comprising cooling the conduit with theoxidizing fluid to reduce heating of the conduit by oxidation.
 3244. Themethod of claim 3238, wherein a conduit is disposed within the opening,the method further comprising removing an oxidation product from theformation through the conduit.
 3245. The method of claim 3238, wherein aconduit is disposed within the opening, the method further comprisingremoving an oxidation product from the formation through the conduit andtransferring heat from the oxidation product in the conduit to theoxidizing fluid in the conduit.
 3246. The method of claim 3238, whereina conduit is disposed within the opening, the method further comprisingremoving an oxidation product from the formation through the conduit,wherein a flow rate of the oxidizing fluid in the conduit isapproximately equal to a flow rate of the oxidation product in theconduit.
 3247. The method of claim 3238, wherein a conduit is disposedwithin the opening, the method further comprising removing an oxidationproduct from the formation through the conduit and controlling apressure between the oxidizing fluid and the oxidation product in theconduit to reduce contamination of the oxidation product by theoxidizing fluid.
 3248. The method of claim 3238, wherein a conduit isdisposed within the opening, the method further comprising removing anoxidation product from the formation through the conduit andsubstantially inhibiting the oxidation product from flowing intoportions of the formation beyond the reaction zone.
 3249. The method ofclaim 3238, further comprising substantially inhibiting the oxidizingfluid from flowing into portions of the formation beyond the reactionzone.
 3250. The method of claim 3238, wherein a center conduit isdisposed within an outer conduit, and wherein the outer conduit isdisposed within the opening, the method further comprising providing theoxidizing fluid into the opening through the center conduit and removingan oxidation product through the outer conduit.
 3251. The method ofclaim 3238, wherein the portion of the formation extends radially fromthe opening a width of less than approximately 0.2 m.
 3252. The methodof claim 3238, further comprising removing water from the formationprior to heating the portion.
 3253. The method of claim 3238, furthercomprising controlling the temperature of the formation to substantiallyinhibit production of oxides of nitrogen during oxidation.
 3254. Themethod of claim 3238, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3255. The method of claim 3238, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3256. The method of claim3238, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3257. The method of claim 3238, further comprising coupling anoverburden casing to the opening, wherein a packing material is disposedat a junction of the overburden casing and the opening.
 3258. The methodof claim 3238, wherein the pyrolysis zone is substantially adjacent tothe reaction zone.
 3259. An in situ method for heating an oil shaleformation, comprising: heating a portion of the formation to atemperature sufficient to support reaction of hydrocarbons within theportion of the formation with an oxidizing fluid, wherein heatingcomprises: oxidizing a fuel gas in a heater, wherein the heater isdisposed external to the formation; providing the oxidized fuel gas fromthe heater to the portion of the formation; allowing heat to transferfrom the oxidized fuel gas to the portion of the formation; providingthe oxidizing fluid to a reaction zone in the formation; allowing theoxidizing fluid to react with at least a portion of the hydrocarbons atthe reaction zone to generate heat at the reaction zone; andtransferring the generated heat substantially by conduction from thereaction zone to a pyrolysis zone in the formation.
 3260. The method ofclaim 3259, further comprising transporting the oxidizing fluid throughthe reaction zone by diffusion.
 3261. The method of claim 3259, furthercomprising directing at least a portion of the oxidizing fluid into theopening through orifices of a conduit disposed in the opening.
 3262. Themethod of claim 3259, further comprising controlling a flow of theoxidizing fluid with critical flow orifices of a conduit disposed in theopening such that a rate of oxidation is controlled.
 3263. The method ofclaim 3259, further comprising increasing a flow of the oxidizing fluidin the opening to accommodate an increase in a volume of the reactionzone such that a rate of oxidation is substantially constant over timewithin the reaction zone.
 3264. The method of claim 3259, wherein aconduit is disposed in the opening, the method further comprisingcooling the conduit with the oxidizing fluid to reduce heating of theconduit by oxidation.
 3265. The method of claim 3259, wherein a conduitis disposed within the opening, the method further comprising removingan oxidation product from the formation through the conduit.
 3266. Themethod of claim 3259, wherein a conduit is disposed within the opening,the method further comprising removing an oxidation product from theformation through the conduit and transferring heat from the oxidationproduct in the conduit to the oxidizing fluid in the conduit.
 3267. Themethod of claim 3259, wherein a conduit is disposed within the opening,the method further comprising removing an oxidation product from theformation through the conduit, wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 3268. The method of claim 3259,wherein a conduit is disposed within the opening, the method furthercomprising removing an oxidation product from the formation through theconduit and controlling a pressure between the oxidizing fluid and theoxidation product in the conduit to reduce contamination of theoxidation product by the oxidizing fluid.
 3269. The method of claim3259, wherein a conduit is disposed within the opening, the methodfurther comprising removing an oxidation product from the formationthrough the conduit and substantially inhibiting the oxidation productfrom flowing into portions of the formation beyond the reaction zone.3270. The method of claim 3259, further comprising substantiallyinhibiting the oxidizing fluid from flowing into portions of theformation beyond the reaction zone.
 3271. The method of claim 3259,wherein a center conduit is disposed within an outer conduit, andwherein the outer conduit is disposed within the opening, the methodfurther comprising providing the oxidizing fluid into the openingthrough the center conduit and removing an oxidation product through theouter conduit.
 3272. The method of claim 3259, wherein the portion ofthe formation extends radially from the opening a width of less thanapproximately 0.2 m.
 3273. The method of claim 3259, further comprisingremoving water from the formation prior to heating the portion. 3274.The method of claim 3259, further comprising controlling the temperatureof the formation to substantially inhibit production of oxides ofnitrogen during oxidation.
 3275. The method of claim 3259, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3276.The method of claim 3259, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3277. The method of claim 3259, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing is further disposed in cement.
 3278. The method of claim 3259,further comprising coupling an overburden casing to the opening, whereina packing material is disposed at a junction of the overburden casingand the opening.
 3279. The method of claim 3259, wherein the pyrolysiszone is substantially adjacent to the reaction zone.
 3280. A systemconfigured to heat an oil shale formation, comprising: an insulatedconductor disposed within an open wellbore in the formation, wherein theinsulated conductor is configured to provide radiant heat to at least aportion of the formation during use; and wherein the system isconfigured to allow heat to transfer from the insulated conductor to aselected section of the formation during use.
 3281. The system of claim3280, wherein the insulated conductor is further configured to generateheat during application of an electrical current to the insulatedconductor during use.
 3282. The system of claim 3280, further comprisinga support member, wherein the support member is configured to supportthe insulated conductor.
 3283. The system of claim 3280, furthercomprising a support member and a centralizer, wherein the supportmember is configured to support the insulated conductor, and wherein thecentralizer is configured to maintain a location of the insulatedconductor on the support member.
 3284. The system of claim 3280, whereinthe open wellbore comprises a diameter of at least approximately 5 cm.3285. The system of claim 3280, further comprising a lead-in conductorcoupled to the insulated conductor, wherein the lead-in conductorcomprises a low resistance conductor configured to generatesubstantially no heat.
 3286. The system of claim 3280, furthercomprising a lead-in conductor coupled to the insulated conductor,wherein the lead-in conductor comprises a rubber insulated conductor.3287. The system of claim 3280, further comprising a lead-in conductorcoupled to the insulated conductor, wherein the lead-in conductorcomprises a copper wire.
 3288. The system of claim 3280, furthercomprising a lead-in conductor coupled to the insulated conductor with acold pin transition conductor.
 3289. The system of claim 3280, furthercomprising a lead-in conductor coupled to the insulated conductor with acold pin transition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 3290. Thesystem of claim 3280, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material is disposed in a sheath.
 3291. Thesystem of claim 3280, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, and whereinthe conductor comprises a copper-nickel alloy.
 3292. The system of claim3280, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, wherein the conductor comprises acopper-nickel alloy, and wherein the copper-nickel alloy comprisesapproximately 7% nickel by weight to approximately 12% nickel by weight.3293. The system of claim 3280, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the conductor comprises a copper-nickel alloy, and wherein thecopper-nickel alloy comprises approximately 2% nickel by weight toapproximately 6% nickel by weight.
 3294. The system of claim 3280,wherein the insulated conductor comprises a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises a thermally conductive material.
 3295. Thesystem of claim 3280, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material comprises magnesium oxide. 3296.The system of claim 3280, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, wherein theelectrically insulating material comprises magnesium oxide, and whereinthe magnesium oxide comprises a thickness of at least approximately 1mm.
 3297. The system of claim 3280, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,and wherein the electrically insulating material comprises aluminumoxide and magnesium oxide.
 3298. The system of claim 3280, wherein theinsulated conductor comprises a conductor disposed in an electricallyinsulating material, wherein the electrically insulating materialcomprises magnesium oxide, wherein the magnesium oxide comprises grainparticles, and wherein the grain particles are configured to occupyporous spaces within the magnesium oxide.
 3299. The system of claim3280, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, and wherein the electricallyinsulating material is disposed in a sheath, and wherein the sheathcomprises a corrosion-resistant material.
 3300. The system of claim3280, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, and wherein the electricallyinsulating material is disposed in a sheath, and wherein the sheathcomprises stainless steel.
 3301. The system of claim 3280, furthercomprising two additional insulated conductors, wherein the insulatedconductor and the two additional insulated conductors are configured ina 3-phase Y configuration.
 3302. The system of claim 3280, furthercomprising an additional insulated conductor, wherein the insulatedconductor and the additional insulated conductor are coupled to asupport member, and wherein the insulated conductor and the additionalinsulated conductor are configured in a series electrical configuration.3303. The system of claim 3280, further comprising an additionalinsulated conductor, wherein the insulated conductor and the additionalinsulated conductor are coupled to a support member, and wherein theinsulated conductor and the additional insulated conductor areconfigured in a parallel electrical configuration.
 3304. The system ofclaim 3280, wherein the insulated conductor is configured to generateradiant heat of approximately 500 W/m to approximately 1150 W/m duringuse.
 3305. The system of claim 3280, further comprising a support memberconfigured to support the insulated conductor, wherein the supportmember comprises orifices configured to provide fluid flow through thesupport member into the open wellbore during use.
 3306. The system ofclaim 3280, further comprising a support member configured to supportthe insulated conductor, wherein the support member comprises criticalflow orifices configured to provide a substantially constant amount offluid flow through the support member into the open wellbore during use.3307. The system of claim 3280, further comprising a tube coupled to theinsulated conductor, wherein the tube is configured to provide a flow offluid into the open wellbore during use.
 3308. The system of claim 3280,further comprising a tube coupled to the insulated conductor, whereinthe tube comprises critical flow orifices configured to provide asubstantially constant amount of fluid flow through the support memberinto the open wellbore during use.
 3309. The system of claim 3280,further comprising an overburden casing coupled to the open wellbore,wherein the overburden casing is disposed in an overburden of theformation.
 3310. The system of claim 3280, further comprising anoverburden casing coupled to the open wellbore, wherein the overburdencasing is disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3311. The system of claim 3280,further comprising an overburden casing coupled to the open wellbore,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3312. The system of claim 3280, further comprising an overburdencasing coupled to the open wellbore, wherein the overburden casing isdisposed in an overburden of the formation, and wherein a packingmaterial is disposed at a junction of the overburden casing and the openwellbore.
 3313. The system of claim 3280, further comprising anoverburden casing coupled to the open wellbore, wherein the overburdencasing is disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and the openwellbore, and wherein the packing material is configured tosubstantially inhibit a flow of fluid between the open wellbore and theoverburden casing during use.
 3314. The system of claim 3280, furthercomprising an overburden casing coupled to the open wellbore, whereinthe overburden casing is disposed in an overburden of the formation,wherein a packing material is disposed at a junction of the overburdencasing and the open wellbore, and wherein the packing material comprisescement.
 3315. The system of claim 3280, further comprising an overburdencasing coupled to the open wellbore, wherein the overburden casing isdisposed in an overburden of the formation, the system furthercomprising a wellhead coupled to the overburden casing and a lead-inconductor coupled to the insulated conductor, wherein the wellhead isdisposed external to the overburden, wherein the wellhead comprises atleast one sealing flange, and wherein at least the one sealing flange isconfigured to couple to the lead-in conductor.
 3316. The system of claim3280, wherein the system is further configured to transfer heat suchthat the transferred heat can pyrolyze at least some of the hydrocarbonsin the selected section.
 3317. A system configurable to heat an oilshale formation, comprising: an insulated conductor configurable to bedisposed within an open wellbore in the formation, wherein the insulatedconductor is further configurable to provide radiant heat to at least aportion of the formation during use; and wherein the system isconfigurable to allow heat to transfer from the insulated conductor to aselected section of the formation during use.
 3318. The system of claim3317, wherein the insulated conductor is further configurable togenerate heat during application of an electrical current to theinsulated conductor during use.
 3319. The system of claim 3317, furthercomprising a support member, wherein the support member is configurableto support the insulated conductor.
 3320. The system of claim 3317,further comprising a support member and a centralizer, wherein thesupport member is configurable to support the insulated conductor, andwherein the centralizer is configurable to maintain a location of theinsulated conductor on the support member.
 3321. The system of claim3317, wherein the open wellbore comprises a diameter of at leastapproximately 5 cm.
 3322. The system of claim 3317, further comprising alead-in conductor coupled to the insulated conductor, wherein thelead-in conductor comprises a low resistance conductor configurable togenerate substantially no heat.
 3323. The system of claim 3317, furthercomprising a lead-in conductor coupled to the insulated conductor,wherein the lead-in conductor comprises a rubber insulated conductor.3324. The system of claim 3317, further comprising a lead-in conductorcoupled to the insulated conductor, wherein the lead-in conductorcomprises a copper wire.
 3325. The system of claim 3317, furthercomprising a lead-in conductor coupled to the insulated conductor with acold pin transition conductor.
 3326. The system of claim 3317, furthercomprising a lead-in conductor coupled to the insulated conductor with acold pin transition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 3327. Thesystem of claim 3317, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material is disposed in a sheath.
 3328. Thesystem of claim 3317, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, and whereinthe conductor comprises a copper-nickel alloy.
 3329. The system of claim3317, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, wherein the conductor comprises acopper-nickel alloy, and wherein the copper-nickel alloy comprisesapproximately 7% nickel by weight to approximately 12% nickel by weight.3330. The system of claim 3317, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the conductor comprises a copper-nickel alloy, and wherein thecopper-nickel alloy comprises approximately 2% nickel by weight toapproximately 6% nickel by weight.
 3331. The system of claim 3317,wherein the insulated conductor comprises a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises a thermally conductive material.
 3332. Thesystem of claim 3317, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material comprises magnesium oxide. 3333.The system of claim 3317, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, wherein theelectrically insulating material comprises magnesium oxide, and whereinthe magnesium oxide comprises a thickness of at least approximately 1mm.
 3334. The system of claim 3317, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,and wherein the electrically insulating material comprises aluminumoxide and magnesium oxide.
 3335. The system of claim 3317, wherein theinsulated conductor comprises a conductor disposed in an electricallyinsulating material, wherein the electrically insulating materialcomprises magnesium oxide, wherein the magnesium oxide comprises grainparticles, and wherein the grain particles are configurable to occupyporous spaces within the magnesium oxide.
 3336. The system of claim3317, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, and wherein the electricallyinsulating material is disposed in a sheath, and wherein the sheathcomprises a corrosion-resistant material.
 3337. The system of claim3317, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, and wherein the electricallyinsulating material is disposed in a sheath, and wherein the sheathcomprises stainless steel.
 3338. The system of claim 3317, furthercomprising two additional insulated conductors, wherein the insulatedconductor and the two additional insulated conductors are configurablein a 3-phase Y configuration.
 3339. The system of claim 3317, furthercomprising an additional insulated conductor, wherein the insulatedconductor and the additional insulated conductor are coupled to asupport member, and wherein the insulated conductor and the additionalinsulated conductor are configurable in a series electricalconfiguration.
 3340. The system of claim 3317, further comprising anadditional insulated conductor, wherein the insulated conductor and theadditional insulated conductor are coupled to a support member, andwherein the insulated conductor and the additional insulated conductorare configurable in a parallel electrical configuration.
 3341. Thesystem of claim 3317, wherein the insulated conductor is configurable togenerate radiant heat of approximately 500 W/m to approximately 1150 W/mduring use.
 3342. The system of claim 3317, further comprising a supportmember configurable to support the insulated conductor, wherein thesupport member comprises orifices configurable to provide fluid flowthrough the support member into the open wellbore during use.
 3343. Thesystem of claim 3317, further comprising a support member configurableto support the insulated conductor, wherein the support member comprisescritical flow orifices configurable to provide a substantially constantamount of fluid flow through the support member into the open wellboreduring use.
 3344. The system of claim 3317, further comprising a tubecoupled to the insulated conductor, wherein the tube is configurable toprovide a flow of fluid into the open wellbore during use.
 3345. Thesystem of claim 3317, further comprising a tube coupled to the firstinsulated conductor, wherein the tube comprises critical flow orificesconfigurable to provide a substantially constant amount of fluid flowthrough the support member into the open wellbore during use.
 3346. Thesystem of claim 3317, further comprising an overburden casing coupled tothe open wellbore, wherein the overburden casing is disposed in anoverburden of the formation.
 3347. The system of claim 3317, furthercomprising an overburden casing coupled to the open wellbore, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3348. The system of claim3317, further comprising an overburden casing coupled to the openwellbore, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing is further disposed incement.
 3349. The system of claim 3317, further comprising an overburdencasing coupled to the open wellbore, wherein the overburden casing isdisposed in an overburden of the formation, and wherein a packingmaterial is disposed at a junction of the overburden casing and the openwellbore.
 3350. The system of claim 3317, further comprising anoverburden casing coupled to the open wellbore, wherein the overburdencasing is disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and the openwellbore, and wherein the packing material is configurable tosubstantially inhibit a flow of fluid between the open wellbore and theoverburden casing during use.
 3351. The system of claim 3317, furthercomprising an overburden casing coupled to the open wellbore, whereinthe overburden casing is disposed in an overburden of the formation,wherein a packing material is disposed at a junction of the overburdencasing and the open wellbore, and wherein the packing material comprisescement.
 3352. The system of claim 3317, further comprising an overburdencasing coupled to the open wellbore, wherein the overburden casing isdisposed in an overburden of the formation, the system furthercomprising a wellhead coupled to the overburden casing and a lead-inconductor coupled to the insulated conductor, wherein the wellhead isdisposed external to the overburden, wherein the wellhead comprises atleast one sealing flange, and wherein at least the one sealing flange isconfigurable to couple to the lead-in conductor.
 3353. The system ofclaim 3317, wherein the system is further configured to transfer heatsuch that the transferred heat can pyrolyze at least some hydrocarbonsin the selected section.
 3354. The system of claim 3317, wherein thesystem is configured to heat an oil shale formation, and wherein thesystem comprises: an insulated conductor disposed within an openwellbore in the formation, wherein the insulated conductor is configuredto provide radiant heat to at least a portion of the formation duringuse; and wherein the system is configured to allow heat to transfer fromthe insulated conductor to a selected section of the formation duringuse.
 3355. An in situ method for heating an oil shale formation,comprising: applying an electrical current to an insulated conductor toprovide radiant heat to at least a portion of the formation, wherein theinsulated conductor is disposed within an open wellbore in theformation; and allowing the radiant heat to transfer from the insulatedconductor to a selected section of the formation.
 3356. The method ofclaim 3355, further comprising supporting the insulated conductor on asupport member.
 3357. The method of claim 3355, further comprisingsupporting the insulated conductor on a support member and maintaining alocation of the insulated conductor on the support member with acentralizer.
 3358. The method of claim 3355, wherein the insulatedconductor is coupled to two additional insulated conductors, wherein theinsulated conductor and the two insulated conductors are disposed withinthe open wellbore, and wherein the three insulated conductors areelectrically coupled in a 3-phase Y configuration.
 3359. The method ofclaim 3355, wherein an additional insulated conductor is disposed withinthe open wellbore.
 3360. The method of claim 3355, wherein an additionalinsulated conductor is disposed within the open wellbore, and whereinthe insulated conductor and the additional insulated conductor areelectrically coupled in a series configuration.
 3361. The method ofclaim 3355, wherein an additional insulated conductor is disposed withinthe open wellbore, and wherein the insulated conductor and theadditional insulated conductor are electrically coupled in a parallelconfiguration.
 3362. The method of claim 3355, wherein the provided heatcomprises approximately 500 W/m to approximately 1150 W/m.
 3363. Themethod of claim 3355, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, and whereinthe conductor comprises a copper-nickel alloy.
 3364. The method of claim3355, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, wherein the conductor comprises acopper-nickel alloy, and wherein the copper-nickel alloy comprisesapproximately 7% nickel by weight to approximately 12% nickel by weight.3365. The method of claim 3355, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the conductor comprises a copper-nickel alloy, and wherein thecopper-nickel alloy comprises approximately 2% nickel by weight toapproximately 6% nickel by weight.
 3366. The method of claim 3355,wherein the insulated conductor comprises a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises magnesium oxide.
 3367. The method of claim3355, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, wherein the electrically insulatingmaterial comprises magnesium oxide, and wherein the magnesium oxidecomprises a thickness of at least approximately 1 mm.
 3368. The methodof claim 3355, wherein the insulated conductor comprises a conductordisposed in an electrically insulating material, and wherein theelectrically insulating material comprises aluminum oxide and magnesiumoxide.
 3369. The method of claim 3355, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the electrically insulating material comprises magnesium oxide,wherein the magnesium oxide comprises grain particles, and wherein thegrain particles are configured to occupy porous spaces within themagnesium oxide.
 3370. The method of claim 3355, wherein the insulatedconductor comprises a conductor disposed in an electrically insulatingmaterial, wherein the insulating material is disposed in a sheath, andwherein the sheath comprises a corrosion-resistant material.
 3371. Themethod of claim 3355, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, wherein theinsulating material is disposed in a sheath, and wherein the sheathcomprises stainless steel.
 3372. The method of claim 3355, furthercomprising supporting the insulated conductor on a support member andflowing a fluid into the open wellbore through an orifice in the supportmember.
 3373. The method of claim 3355, further comprising supportingthe insulated conductor on a support member and flowing a substantiallyconstant amount of fluid into the open wellbore through critical floworifices in the support member.
 3374. The method of claim 3355, whereina perforated tube is disposed in the open wellbore proximate to theinsulated conductor, the method further comprising flowing a fluid intothe open wellbore through the perforated tube.
 3375. The method of claim3355, wherein a tube is disposed in the open wellbore proximate to theinsulated conductor, the method further comprising flowing asubstantially constant amount of fluid into the open wellbore throughcritical flow orifices in the tube.
 3376. The method of claim 3355,further comprising supporting the insulated conductor on a supportmember and flowing a corrosion inhibiting fluid into the open wellborethrough an orifice in the support member.
 3377. The method of claim3355, wherein a perforated tube is disposed in the open wellboreproximate to the insulated conductor, the method further comprisingflowing a corrosion inhibiting fluid into the open wellbore through theperforated tube.
 3378. The method of claim 3355, further comprisingdetermining a temperature distribution in the insulated conductor usingan electromagnetic signal provided to the insulated conductor.
 3379. Themethod of claim 3355, further comprising monitoring a leakage current ofthe insulated conductor.
 3380. The method of claim 3355, furthercomprising monitoring the applied electrical current.
 3381. The methodof claim 3355, further comprising monitoring a voltage applied to theinsulated conductor.
 3382. The method of claim 3355, further comprisingmonitoring a temperature in the insulated conductor with at least onethermocouple.
 3383. The method of claim 3355, further comprisingelectrically coupling a lead-in conductor to the insulated conductor,wherein the lead-in conductor comprises a low resistance conductorconfigured to generate substantially no heat.
 3384. The method of claim3355, further comprising electrically coupling a lead-in conductor tothe insulated conductor using a cold pin transition conductor.
 3385. Themethod of claim 3355, further comprising electrically coupling a lead-inconductor to the insulated conductor using a cold pin transitionconductor, wherein the cold pin transition conductor comprises asubstantially low resistance insulated conductor.
 3386. The method ofclaim 3355, further comprising coupling an overburden casing to the openwellbore, wherein the overburden casing is disposed in an overburden ofthe formation.
 3387. The method of claim 3355, further comprisingcoupling an overburden casing to the open wellbore, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3388. The method of claim3355, further comprising coupling an overburden casing to the openwellbore, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing is further disposed incement.
 3389. The method of claim 3355, further comprising coupling anoverburden casing to the open wellbore, wherein the overburden casing isdisposed in an overburden of the formation, and wherein a packingmaterial is disposed at a junction of the overburden casing and the openwellbore.
 3390. The method of claim 3355, further comprising coupling anoverburden casing to the open wellbore, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the methodfurther comprises inhibiting a flow of fluid between the open wellboreand the overburden casing with a packing material.
 3391. The method ofclaim 3355, further comprising heating at least the portion of theformation to pyrolyze at least some hydrocarbons within the formation.3392. An in situ method for heating an oil shale formation, comprising:applying an electrical current to an insulated conductor to provide heatto at least a portion of the formation, wherein the insulated conductoris disposed within an opening in the formation; and allowing the heat totransfer from the insulated conductor to a section of the formation.3393. The method of claim 3392, further comprising supporting theinsulated conductor on a support member.
 3394. The method of claim 3392,further comprising supporting the insulated conductor on a supportmember and maintaining a location of the first insulated conductor onthe support member with a centralizer.
 3395. The method of claim 3392,wherein the insulated conductor is coupled to two additional insulatedconductors, wherein the insulated conductor and the two insulatedconductors are disposed within the opening, and wherein the threeinsulated conductors are electrically coupled in a 3-phase Yconfiguration.
 3396. The method of claim 3392, wherein an additionalinsulated conductor is disposed within the opening.
 3397. The method ofclaim 3392, wherein an additional insulated conductor is disposed withinthe opening, and wherein the insulated conductor and the additionalinsulated conductor are electrically coupled in a series configuration.3398. The method of claim 3392, wherein an additional insulatedconductor is disposed within the opening, and wherein the insulatedconductor and the additional insulated conductor are electricallycoupled in a parallel configuration.
 3399. The method of claim 3392,wherein the provided heat comprises approximately 500 W/m toapproximately 1150 W/m.
 3400. The method of claim 3392, wherein theinsulated conductor comprises a conductor disposed in an electricallyinsulating material, and wherein the conductor comprises a copper-nickelalloy.
 3401. The method of claim 3392, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the conductor comprises a copper-nickel alloy, and wherein thecopper-nickel alloy comprises approximately 7% nickel by weight toapproximately 12% nickel by weight.
 3402. The method of claim 3392,wherein the insulated conductor comprises a conductor disposed in anelectrically insulating material, wherein the conductor comprises acopper-nickel alloy, and wherein the copper-nickel alloy comprisesapproximately 2% nickel by weight to approximately 6% nickel by weight.3403. The method of claim 3392, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,and wherein the electrically insulating material comprises magnesiumoxide.
 3404. The method of claim 3392, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the electrically insulating material comprises magnesium oxide,and wherein the magnesium oxide comprises a thickness of at leastapproximately 1 mm.
 3405. The method of claim 3392, wherein theinsulated conductor comprises a conductor disposed in an electricallyinsulating material, and wherein the electrically insulating materialcomprises aluminum oxide and magnesium oxide.
 3406. The method of claim3392, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, wherein the electrically insulatingmaterial comprises magnesium oxide, wherein the magnesium oxidecomprises grain particles, and wherein the grain particles areconfigured to occupy porous spaces within the magnesium oxide.
 3407. Themethod of claim 3392, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, wherein theinsulating material is disposed in a sheath, and wherein the sheathcomprises a corrosion-resistant material.
 3408. The method of claim3392, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, wherein the insulating material isdisposed in a sheath, and wherein the sheath comprises stainless steel.3409. The method of claim 3392, further comprising supporting theinsulated conductor on a support member and flowing a fluid into theopening through an orifice in the support member.
 3410. The method ofclaim 3392, further comprising supporting the insulated conductor on asupport member and flowing a substantially constant amount of fluid intothe opening through critical flow orifices in the support member. 3411.The method of claim 3392, wherein a perforated tube is disposed in theopening proximate to the insulated conductor, the method furthercomprising flowing a fluid into the opening through the perforated tube.3412. The method of claim 3392, wherein a tube is disposed in theopening proximate to the insulated conductor, the method furthercomprising flowing a substantially constant amount of fluid into theopening through critical flow orifices in the tube.
 3413. The method ofclaim 3392, further comprising supporting the insulated conductor on asupport member and flowing a corrosion inhibiting fluid into the openingthrough an orifice in the support member.
 3414. The method of claim3392, wherein a perforated tube is disposed in the opening proximate tothe insulated conductor, the method further comprising flowing acorrosion inhibiting fluid into the opening through the perforated tube.3415. The method of claim 3392, further comprising determining atemperature distribution in the insulated conductor using anelectromagnetic signal provided to the insulated conductor.
 3416. Themethod of claim 3392, further comprising monitoring a leakage current ofthe insulated conductor.
 3417. The method of claim 3392, furthercomprising monitoring the applied electrical current.
 3418. The methodof claim 3392, further comprising monitoring a voltage applied to theinsulated conductor.
 3419. The method of claim 3392, further comprisingmonitoring a temperature in the insulated conductor with at least onethermocouple.
 3420. The method of claim 3392, further comprisingelectrically coupling a lead-in conductor to the insulated conductor,wherein the lead-in conductor comprises a low resistance conductorconfigured to generate substantially no heat.
 3421. The method of claim3392, further comprising electrically coupling a lead-in conductor tothe insulated conductor using a cold pin transition conductor.
 3422. Themethod of claim 3392, further comprising electrically coupling a lead-inconductor to the insulated conductor using a cold pin transitionconductor, wherein the cold pin transition conductor comprises asubstantially low resistance insulated conductor.
 3423. The method ofclaim 3392, further comprising coupling an overburden casing to theopening, wherein the overburden casing is disposed in an overburden ofthe formation.
 3424. The method of claim 3392, further comprisingcoupling an overburden casing to the opening, wherein the overburdencasing is disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3425. The method of claim 3392,further comprising coupling an overburden casing to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3426. Themethod of claim 3392, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein a packing material is disposedat a junction of the overburden casing and the opening.
 3427. The methodof claim 3392, further comprising coupling an overburden casing to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the method further comprises inhibiting aflow of fluid between the opening and the overburden casing with apacking material.
 3428. The method of claim 3392, further comprisingheating at least the portion of the formation to substantially pyrolyzeat least some hydrocarbons within the formation.
 3429. A systemconfigured to heat an oil shale formation, comprising: an insulatedconductor disposed within an opening in the formation, wherein theinsulated conductor is configured to provide heat to at least a portionof the formation during use, wherein the insulated conductor comprises acopper-nickel alloy, and wherein the copper-nickel alloy comprisesapproximately 7% nickel by weight to approximately 12% nickel by weight;and wherein the system is configured to allow heat to transfer from theinsulated conductor to a selected section of the formation during use.3430. The system of claim 3429, wherein the insulated conductor isfurther configured to generate heat during application of an electricalcurrent to the insulated conductor during use.
 3431. The system of claim3429, further comprising a support member, wherein the support member isconfigured to support the insulated conductor.
 3432. The system of claim3429, further comprising a support member and a centralizer, wherein thesupport member is configured to support the insulated conductor, andwherein the centralizer is configured to maintain a location of theinsulated conductor on the support member.
 3433. The system of claim3429, wherein the opening comprises a diameter of at least approximately5 cm.
 3434. The system of claim 3429, further comprising a lead-inconductor coupled to the insulated conductor, wherein the lead-inconductor comprises a low resistance conductor configured to generatesubstantially no heat.
 3435. The system of claim 3429, furthercomprising a lead-in conductor coupled to the insulated conductor,wherein the lead-in conductor comprises a rubber insulated conductor.3436. The system of claim 3429, further comprising a lead-in conductorcoupled to the insulated conductor, wherein the lead-in conductorcomprises a copper wire.
 3437. The system of claim 3429, furthercomprising a lead-in conductor coupled to the insulated conductor with acold pin transition conductor.
 3438. The system of claim 3429, furthercomprising a lead-in conductor coupled to the insulated conductor with acold pin transition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 3439. Thesystem of claim 3429, wherein the copper-nickel alloy is disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises a thermally conductive material.
 3440. Thesystem of claim 3429, wherein the copper-nickel alloy is disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises magnesium oxide. 3441 The system of claim3429, wherein the copper-nickel alloy is disposed in an electricallyinsulating material, wherein the electrically insulating materialcomprises magnesium oxide, and wherein the magnesium oxide comprises athickness of at least approximately 1 mm.
 3442. The system of claim3429, wherein the copper-nickel alloy is disposed in an electricallyinsulating material, and wherein the electrically insulating materialcomprises aluminum oxide and magnesium oxide.
 3443. The system of claim3429, wherein the copper-nickel alloy is disposed in an electricallyinsulating material, wherein the electrically insulating materialcomprises magnesium oxide, wherein the magnesium oxide comprises grainparticles, and wherein the grain particles are configured to occupyporous spaces within the magnesium oxide.
 3444. The system of claim3429, wherein the copper-nickel alloy is disposed in an electricallyinsulating material, wherein the electrically insulating material isdisposed in a sheath, and wherein the sheath comprises acorrosion-resistant material.
 3445. The system of claim 3429, whereinthe copper-nickel alloy is disposed in an electrically insulatingmaterial, wherein the electrically insulating material is disposed in asheath, and wherein the sheath comprises stainless steel.
 3446. Thesystem of claim 3429, further comprising two additional insulatedconductors, wherein the insulated conductor and the two additionalinsulated conductors are configured in a 3-phase Y configuration. 3447.The system of claim 3429, further comprising an additional insulatedconductor, wherein the insulated conductor and the additional insulatedconductor are coupled to a support member, and wherein the insulatedconductor and the additional insulated conductor are configured in aseries electrical configuration.
 3448. The system of claim 3429, furthercomprising an additional insulated conductor, wherein the insulatedconductor and the additional insulated conductor are coupled to asupport member, and wherein the insulated conductor and the additionalinsulated conductor are configured in a parallel electricalconfiguration.
 3449. The system of claim 3429, wherein the insulatedconductor is configured to generate radiant heat of approximately 500W/m to approximately 1150 W/m during use.
 3450. The system of claim3429, further comprising a support member configured to support theinsulated conductor, wherein the support member comprises orificesconfigured to provide fluid flow through the support member into theopening during use.
 3451. The system of claim 3429, further comprising asupport member configured to support the insulated conductor, whereinthe support member comprises critical flow orifices configured toprovide a substantially constant amount of fluid flow through thesupport member into the opening during use.
 3452. The system of claim3429, further comprising a tube coupled to the insulated conductor,wherein the tube is configured to provide a flow of fluid into theopening during use.
 3453. The system of claim 3429, further comprising atube coupled to the insulated conductor, wherein the tube comprisescritical flow orifices configured to provide a substantially constantamount of fluid flow through the support member into the opening duringuse.
 3454. The system of claim 3429, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation.
 3455. The system of claim 3429,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3456. The system of claim3429, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3457. The system of claim 3429, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation, and wherein a packing material isdisposed at a junction of the overburden casing and the opening. 3458.The system of claim 3429, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, wherein a packing material is disposed at ajunction of the overburden casing and the opening, and wherein thepacking material is configured to substantially inhibit a flow of fluidbetween the opening and the overburden casing during use.
 3459. Thesystem of claim 3429, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, wherein a packing material is disposed at a junctionof the overburden casing and the opening, and wherein the packingmaterial comprises cement.
 3460. The system of claim 3429, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, thesystem further comprising a wellhead coupled to the overburden casingand a lead-in conductor coupled to the insulated conductor, wherein thewellhead is disposed external to the overburden, wherein the wellheadcomprises at least one sealing flange, and wherein at least the onesealing flange is configured to couple to the lead-in conductor. 3461.The system of claim 3429, wherein the system is further configured totransfer heat such that the transferred heat can pyrolyze at least somehydrocarbons in the selected section.
 3462. A system configurable toheat an oil shale formation, comprising: an insulated conductorconfigurable to be disposed within an opening in the formation, whereinthe insulated conductor is further configurable to provide heat to atleast a portion of the formation during use, wherein the insulatedconductor comprises a copper-nickel alloy, and wherein the copper-nickelalloy comprises approximately 7% nickel by weight to approximately 12%nickel by weight; wherein the system is configurable to allow heat totransfer from the insulated conductor to a selected section of theformation during use.
 3463. The system of claim 3462, wherein theinsulated conductor is further configurable to generate heat duringapplication of an electrical current to the insulated conductor duringuse.
 3464. The system of claim 3462, further comprising a supportmember, wherein the support member is configurable to support theinsulated conductor.
 3465. The system of claim 3462, further comprisinga support member and a centralizer, wherein the support member isconfigurable to support the insulated conductor, and wherein thecentralizer is configurable to maintain a location of the insulatedconductor on the support member.
 3466. The system of claim 3462, whereinthe opening comprises a diameter of at least approximately 5 cm. 3467.The system of claim 3462, further comprising a lead-in conductor coupledto the insulated conductor, wherein the lead-in conductor comprises alow resistance conductor configurable to generate substantially no heat.3468. The system of claim 3462, further comprising a lead-in conductorcoupled to the insulated conductor, wherein the lead-in conductorcomprises a rubber insulated conductor.
 3469. The system of claim 3462,further comprising a lead-in conductor coupled to the insulatedconductor, wherein the lead-in conductor comprises a copper wire. 3470.The system of claim 3462, further comprising a lead-in conductor coupledto the insulated conductor with a cold pin transition conductor. 3471.The system of claim 3462, further comprising a lead-in conductor coupledto the insulated conductor with a cold pin transition conductor, whereinthe cold pin transition conductor comprises a substantially lowresistance insulated conductor.
 3472. The system of claim 3462, whereinthe copper-nickel alloy is disposed in an electrically insulatingmaterial, and wherein the electrically insulating material comprises athermally conductive material.
 3473. The system of claim 3462, whereinthe copper-nickel alloy is disposed in an electrically insulatingmaterial, and wherein the electrically insulating material comprisesmagnesium oxide.
 3474. The system of claim 3462, wherein thecopper-nickel alloy is disposed in an electrically insulating material,wherein the electrically insulating material comprises magnesium oxide,and wherein the magnesium oxide comprises a thickness of at leastapproximately 1 mm.
 3475. The system of claim 3462, wherein thecopper-nickel alloy is disposed in an electrically insulating material,and wherein the electrically insulating material comprises aluminumoxide and magnesium oxide.
 3476. The system of claim 3462, wherein thecopper-nickel alloy is disposed in an electrically insulating material,wherein the electrically insulating material comprises magnesium oxide,wherein the magnesium oxide comprises grain particles, and wherein thegrain particles are configurable to occupy porous spaces within themagnesium oxide.
 3477. The system of claim 3462, wherein thecopper-nickel alloy is disposed in an electrically insulating material,wherein the electrically insulating material is disposed in a sheath,and wherein the sheath comprises a corrosion-resistant material. 3478.The system of claim 3462, wherein the copper-nickel alloy is disposed inan electrically insulating material, wherein the electrically insulatingmaterial is disposed in a sheath, and wherein the sheath comprisesstainless steel.
 3479. The system of claim 3462, further comprising twoadditional insulated conductors, wherein the insulated conductor and thetwo additional insulated conductors are configurable in a 3-phase Yconfiguration.
 3480. The system of claim 3462, further comprising anadditional insulated conductor, wherein the insulated conductor and theadditional insulated conductor are coupled to a support member, andwherein the insulated conductor and the additional insulated conductorare configurable in a series electrical configuration.
 3481. The systemof claim 3462, further comprising an additional insulated conductor,wherein the insulated conductor and the additional insulated conductorare coupled to a support member, and wherein the insulated conductor andthe additional insulated conductor are configurable in a parallelelectrical configuration.
 3482. The system of claim 3462, wherein theinsulated conductor is configurable to generate radiant heat ofapproximately 500 W/m to approximately 1150 W/m during use.
 3483. Thesystem of claim 3462, further comprising a support member configurableto support the insulated conductor, wherein the support member comprisesorifices configurable to provide fluid flow through the support memberinto the open wellbore during use.
 3484. The system of claim 3462,further comprising a support member configurable to support theinsulated conductor, wherein the support member comprises critical floworifices configurable to provide a substantially constant amount offluid flow through the support member into the opening during use. 3485.The system of claim 3462, further comprising a tube coupled to theinsulated conductor, wherein the tube is configurable to provide a flowof fluid into the opening during use.
 3486. The system of claim 3462,further comprising a tube coupled to the insulated conductor, whereinthe tube comprises critical flow orifices configurable to provide asubstantially constant amount of fluid flow through the support memberinto the opening during use.
 3487. The system of claim 3462, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3488.The system of claim 3462, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3489. The system of claim 3462, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3490. The system of claim 3462, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3491. The system of claim 3462, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material is configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 3492. The system of claim 3462, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.3493. The system of claim 3462, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, the system further comprising a wellheadcoupled to the overburden casing and a lead-in conductor coupled to theinsulated conductor, wherein the wellhead is disposed external to theoverburden, wherein the wellhead comprises at least one sealing flange,and wherein at least the one sealing flange is configurable to couple tothe lead-in conductor.
 3494. The system of claim 3462, wherein thesystem is further configured to transfer heat such that the transferredheat can pyrolyze at least some hydrocarbons in the selected section.3495. The system of claim 3462, wherein the system is configured to heatan oil shale formation, and wherein the system comprises: an insulatedconductor disposed within an opening in the formation, wherein theinsulated conductor is configured to provide heat to at least a portionof the formation during use, wherein the insulated conductor comprises acopper-nickel alloy, and wherein the copper-nickel alloy comprisesapproximately 7% nickel by weight to approximately 12% nickel by weight;and wherein the system is configured to allow heat to transfer from theinsulated conductor to a selected section of the formation during use.3496. An in situ method for heating an oil shale formation, comprising:applying an electrical current to an insulated conductor to provide heatto at least a portion of the formation, wherein the insulated conductoris disposed within an opening in the formation, and wherein theinsulated conductor comprises a copper-nickel alloy of approximately 7%nickel by weight to approximately 12% nickel by weight; and allowing theheat to transfer from the insulated conductor to a selected section ofthe formation.
 3497. The method of claim 3496, further comprisingsupporting the insulated conductor on a support member.
 3498. The methodof claim 3496, further comprising supporting the insulated conductor ona support member and maintaining a location of the first insulatedconductor on the support member with a centralizer.
 3499. The method ofclaim 3496, wherein the insulated conductor is coupled to two additionalinsulated conductors, wherein the insulated conductor and the twoinsulated conductors are disposed within the opening, and wherein thethree insulated conductors are electrically coupled in a 3-phase Yconfiguration.
 3500. The method of claim 3496, wherein an additionalinsulated conductor is disposed within the opening.
 3501. The method ofclaim 3496, wherein an additional insulated conductor is disposed withinthe opening, and wherein the insulated conductor and the additionalinsulated conductor are electrically coupled in a series configuration.3502. The method of claim 3496, wherein an additional insulatedconductor is disposed within the opening, and wherein the insulatedconductor and the additional insulated conductor are electricallycoupled in a parallel configuration.
 3503. The method of claim 3496,wherein the provided heat comprises approximately 500 W/m toapproximately 1150 W/m.
 3504. The method of claim 3496, wherein thecopper-nickel alloy is disposed in an electrically insulating material.3505. The method of claim 3496, wherein the copper-nickel alloy isdisposed in an electrically insulating material, and wherein theelectrically insulating material comprises magnesium oxide.
 3506. Themethod of claim 3496, wherein the copper-nickel alloy is disposed in anelectrically insulating material, wherein the electrically insulatingmaterial comprises magnesium oxide, and wherein the magnesium oxidecomprises a thickness of at least approximately 1 mm.
 3507. The methodof claim 3496, wherein the copper-nickel alloy is disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises aluminum oxide and magnesium oxide. 3508.The method of claim 3496, wherein the copper-nickel alloy is disposed inan electrically insulating material, wherein the electrically insulatingmaterial comprises magnesium oxide, wherein the magnesium oxidecomprises grain particles, and wherein the grain particles areconfigured to occupy porous spaces within the magnesium oxide.
 3509. Themethod of claim 3496, wherein the copper-nickel alloy is disposed in anelectrically insulating material, wherein the insulating material isdisposed in a sheath, and wherein the sheath comprises acorrosion-resistant material.
 3510. The method of claim 3496, whereinthe copper-nickel alloy is disposed in an electrically insulatingmaterial, wherein the insulating material is disposed in a sheath, andwherein the sheath comprises stainless steel.
 3511. The method of claim3496, further comprising supporting the insulated conductor on a supportmember and flowing a fluid into the opening through an orifice in thesupport member.
 3512. The method of claim 3496, further comprisingsupporting the insulated conductor on a support member and flowing asubstantially constant amount of fluid into the opening through criticalflow orifices in the support member.
 3513. The method of claim 3496,wherein a perforated tube is disposed in the opening proximate to theinsulated conductor, the method further comprising flowing a fluid intothe opening through the perforated tube.
 3514. The method of claim 3496,wherein a tube is disposed in the opening proximate to the insulatedconductor, the method further comprising flowing a substantiallyconstant amount of fluid into the opening through critical flow orificesin the tube.
 3515. The method of claim 3496, further comprisingsupporting the insulated conductor on a support member and flowing acorrosion inhibiting fluid into the opening through an orifice in thesupport member.
 3516. The method of claim 3496, wherein a perforatedtube is disposed in the opening proximate to the insulated conductor,the method further comprising flowing a corrosion inhibiting fluid intothe opening through the perforated tube.
 3517. The method of claim 3496,further comprising determining a temperature distribution in theinsulated conductor using an electromagnetic signal provided to theinsulated conductor.
 3518. The method of claim 3496, further comprisingmonitoring a leakage current of the insulated conductor.
 3519. Themethod of claim 3496, further comprising monitoring the appliedelectrical current.
 3520. The method of claim 3496, further comprisingmonitoring a voltage applied to the insulated conductor.
 3521. Themethod of claim 3496, further comprising monitoring a temperature in theinsulated conductor with at least one thermocouple.
 3522. The method ofclaim 3496, further comprising electrically coupling a lead-in conductorto the insulated conductor, wherein the lead-in conductor comprises alow resistance conductor configured to generate substantially no heat.3523. The method of claim 3496, further comprising electrically couplinga lead-in conductor to the insulated conductor using a cold pintransition conductor.
 3524. The method of claim 3496, further comprisingelectrically coupling a lead-in conductor to the insulated conductorusing a cold pin transition conductor, wherein the cold pin transitionconductor comprises a substantially low resistance insulated conductor.3525. The method of claim 3496, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation.
 3526. The method of claim3496, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing comprises steel.
 3527. Themethod of claim 3496, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3528. The method of claim 3496, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3529. The method of claim 3496, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the method further comprises inhibiting a flow of fluid betweenthe opening and the overburden casing with a packing material.
 3530. Themethod of claim 3496, further comprising heating at least the portion ofthe formation to substantially pyrolyze at least some hydrocarbonswithin the formation.
 3531. A system configured to heat an oil shaleformation, comprising: at least three insulated conductors disposedwithin an opening in the formation, wherein at least the three insulatedconductors are electrically coupled in a 3-phase Y configuration, andwherein at least the three insulated conductors are configured toprovide heat to at least a portion of the formation during use; andwherein the system is configured to allow heat to transfer from at leastthe three insulated conductors to a selected section of the formationduring use.
 3532. The system of claim 3531, wherein at least the threeinsulated conductors are further configured to generate heat duringapplication of an electrical current to at least the three insulatedconductors during use.
 3533. The system of claim 3531, furthercomprising a support member, wherein the support member is configured tosupport at least the three insulated conductors.
 3534. The system ofclaim 3531, further comprising a support member and a centralizer,wherein the support member is configured to support at least the threeinsulated conductors, and wherein the centralizer is configured tomaintain a location of at least the three insulated conductors on thesupport member.
 3535. The system of claim 3531, wherein the openingcomprises a diameter of at least approximately 5 cm.
 3536. The system ofclaim 3531, further comprising at least one lead-in conductor coupled toat least the three insulated conductors, wherein at least the onelead-in conductor comprises a low resistance conductor configured togenerate substantially no heat.
 3537. The system of claim 3531, furthercomprising at least one lead-in conductor coupled to at least the threeinsulated conductors, wherein at least the one lead-in conductorcomprises a rubber insulated conductor.
 3538. The system of claim 3531,further comprising at least one lead-in conductor coupled to at leastthe three insulated conductors, wherein at least the one lead-inconductor comprises a copper wire.
 3539. The system of claim 3531,further comprising at least one lead-in conductor coupled to at leastthe three insulated conductors with a cold pin transition conductor.3540. The system of claim 3531, further comprising at least one lead-inconductor coupled to at least the three insulated conductors with a coldpin transition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 3541. Thesystem of claim 3531, wherein at least the three insulated conductorscomprise a conductor disposed in an electrically insulating material,and wherein the electrically insulating material is disposed in asheath.
 3542. The system of claim 3531, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, and wherein the conductor comprises a copper-nickelalloy.
 3543. The system of claim 3531, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, wherein the conductor comprises a copper-nickelalloy, and wherein the copper-nickel alloy comprises approximately 7%nickel by weight to approximately 12% nickel by weight.
 3544. The systemof claim 3531, wherein at least the three insulated conductors comprisea conductor disposed in an electrically insulating material, wherein theconductor comprises a copper-nickel alloy, and wherein the copper-nickelalloy comprises approximately 2% nickel by weight to approximately 6%nickel by weight.
 3545. The system of claim 3531, wherein at least thethree insulated conductors comprise a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises a thermally conductive material.
 3546. Thesystem of claim 3531, wherein at least the three insulated conductorscomprise a conductor disposed in an electrically insulating material,and wherein the electrically insulating material comprises magnesiumoxide.
 3547. The system of claim 3531, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, wherein the electrically insulating materialcomprises magnesium oxide, and wherein the magnesium oxide comprises athickness of at least approximately 1 mm.
 3548. The system of claim3531, wherein at least the three insulated conductors comprise aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material comprises aluminum oxide andmagnesium oxide.
 3549. The system of claim 3531, wherein the insulatedconductor comprises a conductor disposed in an electrically insulatingmaterial, wherein the electrically insulating material comprisesmagnesium oxide, wherein the magnesium oxide comprises grain particles,and wherein the grain particles are configured to occupy porous spaceswithin the magnesium oxide.
 3550. The system of claim 3531, wherein atleast the three insulated conductors comprise a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material is disposed in a sheath, and wherein the sheathcomprises a corrosion-resistant material.
 3551. The system of claim3531, wherein at least the three insulated conductors comprise aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material is disposed in a sheath, andwherein the sheath comprises stainless steel.
 3552. The system of claim3531, wherein at least the three insulated conductors are configured togenerate radiant heat of approximately 500 W/m to approximately 1150 W/mof at least the three insulated conductors during use.
 3553. The systemof claim 3531, further comprising a support member configured to supportat least the three insulated conductors, wherein the support membercomprises orifices configured to provide fluid flow through the supportmember into the opening during use.
 3554. The system of claim 3531,further comprising a support member configured to support at least thethree insulated conductors, wherein the support member comprisescritical flow orifices configured to provide a substantially constantamount of fluid flow through the support member into the opening duringuse.
 3555. The system of claim 3531, further comprising a tube coupledto at least the three insulated conductors, wherein the tube isconfigured to provide a flow of fluid into the opening during use. 3556.The system of claim 3531, further comprising a tube coupled to at leastthe three insulated conductors, wherein the tube comprises critical floworifices configured to provide a substantially constant amount of fluidflow through the support member into the opening during use.
 3557. Thesystem of claim 3531, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 3558. The system of claim 3531, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3559. The system of claim 3531,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3560. Thesystem of claim 3531, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3561. The system ofclaim 3531, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3562. The system of claim3531, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3563. The system of claim 3531, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, the system furthercomprising a wellhead coupled to the overburden casing and a lead-inconductor coupled to the insulated conductor, wherein the wellhead isdisposed external to the overburden, wherein the wellhead comprises atleast one sealing flange, and wherein at least the one sealing flange isconfigured to couple to the lead-in conductor.
 3564. The system of claim3531, wherein the system is further configured to transfer heat suchthat the transferred heat can pyrolyze at least some hydrocarbons in theselected section.
 3565. A system configurable to heat an oil shaleformation, comprising: at least three insulated conductors configurableto be disposed within an opening in the formation, wherein at least thethree insulated conductors are electrically coupled in a 3-phase Yconfiguration, and wherein at least the three insulated conductors arefurther configurable to provide heat to at least a portion of theformation during use; and wherein the system is configurable to allowheat to transfer from at least the three insulated conductors to aselected section of the formation during use.
 3566. The system of claim3565, wherein at least the three insulated conductors are furtherconfigurable to generate heat during application of an electricalcurrent to at least the three insulated conductors during use.
 3567. Thesystem of claim 3565, further comprising a support member, wherein thesupport member is configurable to support at least the three insulatedconductors.
 3568. The system of claim 3565, further comprising a supportmember and a centralizer, wherein the support member is configurable tosupport at least the three insulated conductors, and wherein thecentralizer is configurable to maintain a location of at least the threeinsulated conductors on the support member.
 3569. The system of claim3565, wherein the opening comprises a diameter of at least approximately5 cm.
 3570. The system of claim 3565, further comprising at least onelead-in conductor coupled to at least the three insulated conductors,wherein at least the one lead-in conductor comprises a low resistanceconductor configurable to generate substantially no heat.
 3571. Thesystem of claim 3565, further comprising at least one lead-in conductorcoupled to at least the three insulated conductors, wherein at least theone lead-in conductor comprises a rubber insulated conductor.
 3572. Thesystem of claim 3565, further comprising at least one lead-in conductorcoupled to at least the three insulated conductors, wherein at least theone lead-in conductor comprises a copper wire.
 3573. The system of claim3565, further comprising at least one lead-in conductor coupled to atleast the three insulated conductors with a cold pin transitionconductor.
 3574. The system of claim 3565, further comprising at leastone lead-in conductor coupled to at least the three insulated conductorswith a cold pin transition conductor, wherein the cold pin transitionconductor comprises a substantially low resistance insulated conductor.3575. The system of claim 3565, wherein at least the three insulatedconductors comprise a conductor disposed in an electrically insulatingmaterial, and wherein the electrically insulating material is disposedin a sheath.
 3576. The system of claim 3565, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, and wherein the conductor comprises a copper-nickelalloy.
 3577. The system of claim 3565, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, wherein the conductor comprises a copper-nickelalloy, and wherein the copper-nickel alloy comprises approximately 7%nickel by weight to approximately 12% nickel by weight.
 3578. The systemof claim 3565, wherein at least the three insulated conductors comprisea conductor disposed in an electrically insulating material, wherein theconductor comprises a copper-nickel alloy, and wherein the copper-nickelalloy comprises approximately 2% nickel by weight to approximately 6%nickel by weight.
 3579. The system of claim 3565, wherein at least thethree insulated conductors comprise a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises a thermally conductive material.
 3580. Thesystem of claim 3565, wherein at least the three insulated conductorscomprise a conductor disposed in an electrically insulating material,and wherein the electrically insulating material comprises magnesiumoxide.
 3581. The system of claim 3565, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, wherein the electrically insulating materialcomprises magnesium oxide, and wherein the magnesium oxide comprises athickness of at least approximately 1 mm.
 3582. The system of claim3565, wherein at least the three insulated conductors comprise aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material comprises aluminum oxide andmagnesium oxide.
 3583. The system of claim 3565, wherein the insulatedconductor comprises a conductor disposed in an electrically insulatingmaterial, wherein the electrically insulating material comprisesmagnesium oxide, wherein the magnesium oxide comprises grain particles,and wherein the grain particles are configurable to occupy porous spaceswithin the magnesium oxide.
 3584. The system of claim 3565, wherein atleast the three insulated conductors comprise a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material is disposed in a sheath, and wherein the sheathcomprises a corrosion-resistant material.
 3585. The system of claim3565, wherein at least the three insulated conductors comprise aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material is disposed in a sheath, andwherein the sheath comprises stainless steel.
 3586. The system of claim3565, wherein at least the three insulated conductors are configurableto generate radiant heat of approximately 500 W/m to approximately 1150W/m during use.
 3587. The system of claim 3565, further comprising asupport member configurable to support at least the three insulatedconductors, wherein the support member comprises orifices configurableto provide fluid flow through the support member into the opening duringuse.
 3588. The system of claim 3565, further comprising a support memberconfigurable to support at least the three insulated conductors, whereinthe support member comprises critical flow orifices configurable toprovide a substantially constant amount of fluid flow through thesupport member into the opening during use.
 3589. The system of claim3565, further comprising a tube coupled to at least the three insulatedconductors, wherein the tube is configurable to provide a flow of fluidinto the opening during use.
 3590. The system of claim 3565, furthercomprising a tube coupled to at least the three insulated conductors,wherein the tube comprises critical flow orifices configurable toprovide a substantially constant amount of fluid flow through thesupport member into the opening during use.
 3591. The system of claim3565, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation.
 3592. The system of claim 3565, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3593. The system of claim 3565,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3594. Thesystem of claim 3565, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3595. The system ofclaim 3565, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configurable to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3596. The system of claim3565, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3597. The system of claim 3565, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, the system furthercomprising a wellhead coupled to the overburden casing and a lead-inconductor coupled to the insulated conductor, wherein the wellhead isdisposed external to the overburden, wherein the wellhead comprises atleast one sealing flange, and wherein at least the one sealing flange isconfigurable to couple to the lead-in conductor.
 3598. The system ofclaim 3565, wherein the system is further configured to transfer heatsuch that the transferred heat can pyrolyze at least some hydrocarbonsin the selected section.
 3599. The system of claim 3565, wherein thesystem is configured to heat an oil shale formation, and wherein thesystem comprises: at least three insulated conductors disposed within anopening in the formation, wherein at least the three insulatedconductors are electrically coupled in a 3-phase Y configuration, andwherein at least the three insulated conductors are configured toprovide heat to at least a portion of the formation during use; andwherein the system is configured to allow heat to transfer from at leastthe three insulated conductors to a selected section of the formationduring use.
 3600. An in situ method for heating an oil shale formation,comprising: applying an electrical current to at least three insulatedconductors to provide heat to at least a portion of the formation,wherein at least the three insulated conductors are disposed within anopening in the formation; and allowing the heat to transfer from atleast the three insulated conductors to a selected section of theformation.
 3601. The method of claim 3600, further comprising supportingat least the three insulated conductors on a support member.
 3602. Themethod of claim 3600, further comprising supporting at least the threeinsulated conductors on a support member and maintaining a location ofat least the three insulated conductors on the support member with acentralizer.
 3603. The method of claim 3600, wherein the provided heatcomprises approximately 500 W/m to approximately 1150 W/m.
 3604. Themethod of claim 3600, wherein at least the three insulated conductorscomprise a conductor disposed in an electrically insulating material,and wherein the conductor comprises a copper-nickel alloy.
 3605. Themethod of claim 3600, wherein at least the three insulated conductorscomprise a conductor disposed in an electrically insulating material,wherein the conductor comprises a copper-nickel alloy, and wherein thecopper-nickel alloy
 3606. The method of claim 3600, wherein at least thethree insulated conductors comprise a conductor disposed in anelectrically insulating material, wherein the conductor comprises acopper-nickel alloy, and wherein the copper-nickel alloy comprisesapproximately 2% nickel by weight to approximately 6% nickel by weight.3607. The method of claim 3600, wherein at least the three insulatedconductors comprise a conductor disposed in an electrically insulatingmaterial, and wherein the electrically insulating material comprisesmagnesium oxide.
 3608. The method of claim 3600, wherein at least thethree insulated conductors comprise a conductor disposed in anelectrically insulating material, wherein the electrically insulatingmaterial comprises magnesium oxide, and wherein the magnesium oxidecomprises a thickness of at least approximately 1 mm.
 3609. The methodof claim 3600, wherein at least the three insulated conductors comprisea conductor disposed in an electrically insulating material, and whereinthe electrically insulating material comprises aluminum oxide andmagnesium oxide.
 3610. The method of claim 3600, wherein at least thethree insulated conductors comprise a conductor disposed in anelectrically insulating material, wherein the electrically insulatingmaterial comprises magnesium oxide, wherein the magnesium oxidecomprises grain particles, and wherein the grain particles areconfigured to occupy porous spaces within the magnesium oxide.
 3611. Themethod of claim 3600, wherein at least the three insulated conductorscomprise a conductor disposed in an electrically insulating material,wherein the insulating material is disposed in a sheath, and wherein thesheath comprises a corrosion-resistant material.
 3612. The method ofclaim 3600, wherein at least the three insulated conductors comprise aconductor disposed in an electrically insulating material, wherein theinsulating material is disposed in a sheath, and wherein the sheathcomprises stainless steel.
 3613. The method of claim 3600, furthercomprising supporting at least the three insulated conductors on asupport member and flowing a fluid into the opening through an orificein the support member.
 3614. The method of claim 3600, furthercomprising supporting at least the three insulated conductors on asupport member and flowing a substantially constant amount of fluid intothe opening through critical flow orifices in the support member. 3615.The method of claim 3600, wherein a perforated tube is disposed in theopening proximate to at least the three insulated conductors, the methodfurther comprising flowing a fluid into the opening through theperforated tube.
 3616. The method of claim 3600, wherein a tube isdisposed in the opening proximate to at least the three insulatedconductors, the method further comprising flowing a substantiallyconstant amount of fluid into the opening through critical flow orificesin the tube.
 3617. The method of claim 3600, further comprisingsupporting at least the three insulated conductors on a support memberand flowing a corrosion inhibiting fluid into the opening through anorifice in the support member.
 3618. The method of claim 3600, wherein aperforated tube is disposed in the opening proximate to at least thethree insulated conductors, the method further comprising flowing acorrosion inhibiting fluid into the opening through the perforated tube.3619. The method of claim 3600, further comprising determining atemperature distribution in at least the three insulated conductorsusing an electromagnetic signal provided to the insulated conductor.3620. The method of claim 3600, further comprising monitoring a leakagecurrent of at least the three insulated conductors.
 3621. The method ofclaim 3600, further comprising monitoring the applied electricalcurrent.
 3622. The method of claim 3600, further comprising monitoring avoltage applied to at least the three insulated conductors.
 3623. Themethod of claim 3600, further comprising monitoring a temperature in atleast the three insulated conductors with at least one thermocouple.3624. The method of claim 3600, further comprising electrically couplinga lead-in conductor to at least the three insulated conductors, whereinthe lead-in conductor comprises a low resistance conductor configured togenerate substantially no heat.
 3625. The method of claim 3600, furthercomprising electrically coupling a lead-in conductor to at least thethree insulated conductors using a cold pin transition conductor. 3626.The method of claim 3600, further comprising electrically coupling alead-in conductor to at least the three insulated conductors using acold pin transition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 3627. Themethod of claim 3600, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3628. The method of claim 3600, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3629. The method of claim3600, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3630. The method of claim 3600, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein a packingmaterial is disposed at a junction of the overburden casing and theopening.
 3631. The method of claim 3600, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the methodfurther comprises inhibiting a flow of fluid between the opening and theoverburden casing with a packing material.
 3632. The method of claim3600, further comprising heating at least the portion of the formationto substantially pyrolyze at least some of the hydrocarbons within theformation.
 3633. A system configured to heat an oil shale formation,comprising: a first conductor disposed in a first conduit, wherein thefirst conduit is disposed within an opening in the formation, andwherein the first conductor is configured to provide heat to at least aportion of the formation during use; and wherein the system isconfigured to allow heat to transfer from the first conductor to asection of the formation during use.
 3634. The system of claim 3633,wherein the first conductor is further configured to generate heatduring application of an electrical current to the first conductor.3635. The system of claim 3633, wherein the first conductor comprises apipe.
 3636. The system of claim 3633, wherein the first conductorcomprises stainless steel.
 3637. The system of claim 3633, wherein thefirst conduit comprises stainless steel.
 3638. The system of claim 3633,further comprising a centralizer configured to maintain a location ofthe first conductor within the first conduit.
 3639. The system of claim3633, further comprising a centralizer configured to maintain a locationof the first conductor within the first conduit, wherein the centralizercomprises ceramic material.
 3640. The system of claim 3633, furthercomprising a centralizer configured to maintain a location of the firstconductor within the first conduit, wherein the centralizer comprisesceramic material and stainless steel.
 3641. The system of claim 3633,wherein the opening comprises a diameter of at least approximately 5 cm.3642. The system of claim 3633, further comprising a lead-in conductorcoupled to the first conductor, wherein the lead-in conductor comprisesa low resistance conductor configured to generate substantially no heat.3643. The system of claim 3633, further comprising a lead-in conductorcoupled to the first conductor, wherein the lead-in conductor comprisescopper.
 3644. The system of claim 3633, further comprising a slidingelectrical connector coupled to the first conductor.
 3645. The system ofclaim 3633, further comprising a sliding electrical connector coupled tothe first conductor, wherein the sliding electrical connector is furthercoupled to the first conduit.
 3646. The system of claim 3633, furthercomprising a sliding electrical connector coupled to the firstconductor, wherein the sliding electrical connector is further coupledto the first conduit, and wherein the sliding electrical connector isconfigured to complete an electrical circuit with the first conductorand the first conduit.
 3647. The system of claim 3633, furthercomprising a second conductor disposed within the first conduit and atleast one sliding electrical connector coupled to the first conductorand the second conductor, wherein at least the one sliding electricalconnector is configured to generate less heat than the first conductoror the second conductor during use.
 3648. The system of claim 3633,wherein the first conduit comprises a first section and a secondsection, wherein a thickness of the first section is greater than athickness of the second section such that heat radiated from the firstconductor to the section along the first section of the conduit is lessthan heat radiated from the first conductor to the section along thesecond section of the conduit.
 3649. The system of claim 3633, furthercomprising a fluid disposed within the first conduit, wherein the fluidis configured to maintain a pressure within the first conduit tosubstantially inhibit deformation of the first conduit during use. 3650.The system of claim 3633, further comprising a thermally conductivefluid disposed within the first conduit.
 3651. The system of claim 3633,further comprising a thermally conductive fluid disposed within thefirst conduit, wherein the thermally conductive fluid comprises helium.3652. The system of claim 3633, further comprising a fluid disposedwithin the first conduit, wherein the fluid is configured tosubstantially inhibit arcing between the first conductor and the firstconduit during use.
 3653. The system of claim 3633, further comprising atube disposed within the opening external to the first conduit, whereinthe tube is configured to remove vapor produced from at least the heatedportion of the formation such that a pressure balance is maintainedbetween the first conduit and the opening to substantially inhibitdeformation to of the first conduit during use.
 3654. The system ofclaim 3633, wherein the first conductor is further configured togenerate radiant heat of approximately 650 W/m to approximately 1650 W/mduring use.
 3655. The system of claim 3633, further comprising a secondconductor disposed within a second conduit and a third conductordisposed within a third conduit, wherein the first conduit, the secondconduit and the third conduit are disposed in different openings of theformation, wherein the first conductor is electrically coupled to thesecond conductor and the third conductor, and wherein the first, second,and third conductors are configured to operate in a 3-phase Yconfiguration during use.
 3656. The system of claim 3633, furthercomprising a second conductor disposed within the first conduit, whereinthe second conductor is electrically coupled to the first conductor toform an electrical circuit.
 3657. The system of claim 3633, furthercomprising a second conductor disposed within the first conduit, whereinthe second conductor is electrically coupled to the first conductor toform an electrical circuit with a connector.
 3658. The system of claim3633, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation.
 3659. The system of claim 3633, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3660. The system of claim 3633,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3661. Thesystem of claim 3633, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3662. The system ofclaim 3633, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis further configured to substantially inhibit a flow of fluid betweenthe opening and the overburden casing during use.
 3663. The system ofclaim 3633, further comprising an overburden casing coupled to theopening and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to the first conductor.
 3664. The system of claim3633, further comprising an overburden casing coupled to the opening anda substantially low resistance conductor disposed within the overburdencasing, wherein the substantially low resistance conductor iselectrically coupled to the first conductor, and wherein thesubstantially low resistance conductor comprises carbon steel.
 3665. Thesystem of claim 3633, further comprising an overburden casing coupled tothe opening and a substantially low resistance conductor disposed withinthe overburden casing and a centralizer configured to support thesubstantially low resistance conductor within the overburden casing.3666. The system of claim 3633, wherein the heated section of theformation is substantially pyrolyzed.
 3667. A system configurable toheat an oil shale formation, comprising: a first conductor configurableto be disposed in a first conduit, wherein the first conduit isconfigurable to be disposed within an opening in the formation, andwherein the first conductor is further configurable to provide heat toat least a portion of the formation during use; and wherein the systemis configurable to allow heat to transfer from the first conductor to asection of the formation during use.
 3668. The system of claim 3667,wherein the first conductor is further configurable to generate heatduring application of an electrical current to the first conductor.3669. The system of claim 3667, wherein the first conductor comprises apipe.
 3670. The system of claim 3667, wherein the first conductorcomprises stainless steel.
 3671. The system of claim 3667, wherein thefirst conduit comprises stainless steel.
 3672. The system of claim 3667,further comprising a centralizer configurable to maintain a location ofthe first conductor within the first conduit.
 3673. The system of claim3667, further comprising a centralizer configurable to maintain alocation of the first conductor within the first conduit, wherein thecentralizer comprises ceramic material.
 3674. The system of claim 3667,further comprising a centralizer configurable to maintain a location ofthe first conductor within the first conduit, wherein the centralizercomprises ceramic material and stainless steel.
 3675. The system ofclaim 3667, wherein the opening comprises a diameter of at leastapproximately 5 cm.
 3676. The system of claim 3667, further comprising alead-in conductor coupled to the first conductor, wherein the lead-inconductor comprises a low resistance conductor configurable to generatesubstantially no heat.
 3677. The system of claim 3667, furthercomprising a lead-in conductor coupled to the first conductor, whereinthe lead-in conductor comprises copper.
 3678. The system of claim 3667,further comprising a sliding electrical connector coupled to the firstconductor.
 3679. The system of claim 3667, further comprising a slidingelectrical connector coupled to the first conductor, wherein the slidingelectrical connector is further coupled to the first conduit.
 3680. Thesystem of claim 3667, further comprising a sliding electrical connectorcoupled to the first conductor, wherein the sliding electrical connectoris further coupled to the first conduit, and wherein the slidingelectrical connector is configurable to complete an electrical circuitwith the first conductor and the first conduit.
 3681. The system ofclaim 3667, further comprising a second conductor disposed within thefirst conduit and at least one sliding electrical connector coupled tothe first conductor and the second conductor, wherein at least the onesliding electrical connector is configurable to generate less heat thanthe first conductor or the second conductor during use.
 3682. The systemof claim 3667, wherein the first conduit comprises a first section and asecond section, wherein a thickness of the first section is greater thana thickness of the second section such that heat radiated from the firstconductor to the section along the first section of the conduit is lessthan heat radiated from the first conductor to the section along thesecond section of the conduit.
 3683. The system of claim 3667, furthercomprising a fluid disposed within the first conduit, wherein the fluidis configurable to maintain a pressure within the first conduit tosubstantially inhibit deformation of the first conduit during use. 3684.The system of claim 3667, further comprising a thermally conductivefluid disposed within the first conduit.
 3685. The system of claim 3667,further comprising a thermally conductive fluid disposed within thefirst conduit, wherein the thermally conductive fluid comprises helium.3686. The system of claim 3667, further comprising a fluid disposedwithin the first conduit, wherein the fluid is configurable tosubstantially inhibit arcing between the first conductor and the firstconduit during use.
 3687. The system of claim 3667, further comprising atube disposed within the opening external to the first conduit, whereinthe tube is configurable to remove vapor produced from at least theheated portion of the formation such that a pressure balance ismaintained between the first conduit and the opening to substantiallyinhibit deformation of the first conduit during use.
 3688. The system ofclaim 3667, wherein the first conductor is further configurable togenerate radiant heat of approximately 650 W/m to approximately 1650 W/mduring use.
 3689. The system of claim 3667, further comprising a secondconductor disposed within a second conduit and a third conductordisposed within a third conduit, wherein the first conduit, the secondconduit and the third conduit are disposed in different openings of theformation, wherein the first conductor is electrically coupled to thesecond conductor and the third conductor, and wherein the first, second,and third conductors are configurable to operate in a 3-phase Yconfiguration during use.
 3690. The system of claim 3667, furthercomprising a second conductor disposed within the first conduit, whereinthe second conductor is electrically coupled to the first conductor toform an electrical circuit.
 3691. The system of claim 3667, furthercomprising a second conductor disposed within the first conduit, whereinthe second conductor is electrically coupled to the first conductor toform an electrical circuit with a connector.
 3692. The system of claim3667, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation.
 3693. The system of claim 3667, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3694. The system of claim 3667,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3695. Thesystem of claim 3667, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3696. The system ofclaim 3667, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis further configurable to substantially inhibit a flow of fluid betweenthe opening and the overburden casing during use.
 3697. The system ofclaim 3667, further comprising an overburden casing coupled to theopening and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to the first conductor.
 3698. The system of claim3667, further comprising an overburden casing coupled to the opening anda substantially low resistance conductor disposed within the overburdencasing, wherein the substantially low resistance conductor iselectrically coupled to the first conductor, and wherein thesubstantially low resistance conductor comprises carbon steel.
 3699. Thesystem of claim 3667, further comprising an overburden casing coupled tothe opening and a substantially low resistance conductor disposed withinthe overburden casing and a centralizer configurable to support thesubstantially low resistance conductor within the overburden casing.3700. The system of claim 3667, wherein the heated section of theformation is substantially pyrolyzed.
 3701. The system of claim 3667,wherein the system is configured to heat an oil shale formation, andwherein the system comprises: a first conductor disposed in a firstconduit, wherein the first conduit is disposed within an opening in theformation, and wherein the first conductor is configured to provide heatto at least a portion of the formation during use; and wherein thesystem is configured to allow heat to transfer from the first conductorto a section of the formation during use.
 3702. An in situ method forheating an oil shale formation, comprising: applying an electricalcurrent to a first conductor to provide heat to at least a portion ofthe formation, wherein the first conductor is disposed in a firstconduit, and wherein the first conduit is disposed within an opening inthe formation; and allowing the heat to transfer from the firstconductor to a section of the formation.
 3703. The method of claim 3702,wherein the first conductor comprises a pipe.
 3704. The method of claim3702, wherein the first conductor comprises stainless steel.
 3705. Themethod of claim 3702, wherein the first conduit comprises stainlesssteel.
 3706. The method of claim 3702, further comprising maintaining alocation of the first conductor in the first conduit with a centralizer.3707. The method of claim 3702, further comprising maintaining alocation of the first conductor in the first conduit with a centralizer,wherein the centralizer comprises ceramic material.
 3708. The method ofclaim 3702, further comprising maintaining a location of the firstconductor in the first conduit with a centralizer, wherein thecentralizer comprises ceramic material and stainless steel.
 3709. Themethod of claim 3702, further comprising coupling a sliding electricalconnector to the first conductor.
 3710. The method of claim 3702,further comprising electrically coupling a sliding electrical connectorto the first conductor and the first conduit, wherein the first conduitcomprises an electrical lead configured to complete an electricalcircuit with the first conductor.
 3711. The method of claim 3702,further comprising coupling a sliding electrical connector to the firstconductor and the first conduit, wherein the first conduit comprises anelectrical lead configured to complete an electrical circuit with thefirst conductor, and wherein the generated heat comprises approximately20 percent generated by the first conduit.
 3712. The method of claim3702, wherein the provided heat comprises approximately 650 W/m toapproximately 1650 W/m.
 3713. The method of claim 3702, furthercomprising determining a temperature distribution in the first conduitusing an electromagnetic signal provided to the conduit.
 3714. Themethod of claim 3702, further comprising monitoring the appliedelectrical current.
 3715. The method of claim 3702, further comprisingmonitoring a voltage applied to the first conductor.
 3716. The method ofclaim 3702, further comprising monitoring a temperature in the conduitwith at least one thermocouple.
 3717. The method of claim 3702, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3718.The method of claim 3702, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3719. The method of claim 3702, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing is further disposed in cement.
 3720. The method of claim 3702,further comprising coupling an overburden casing to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3721. The method of claim 3702, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the method further comprises inhibiting a flow of fluid betweenthe opening and the overburden casing with a packing material.
 3722. Themethod of claim 3702, further comprising coupling an overburden casingto the opening, wherein a substantially low resistance conductor isdisposed within the overburden casing, and wherein the substantially lowresistance conductor is electrically coupled to the first conductor.3723. The method of claim 3702, further comprising coupling anoverburden casing to the opening, wherein a substantially low resistanceconductor is disposed within the overburden casing, wherein thesubstantially low resistance conductor is electrically coupled to thefirst conductor, and wherein the substantially low resistance conductorcomprises carbon steel.
 3724. The method of claim 3702, furthercomprising coupling an overburden casing to the opening, wherein asubstantially low resistance conductor is disposed within the overburdencasing, wherein the substantially low resistance conductor iselectrically coupled to the first conductor, and wherein the methodfurther comprises maintaining a location of the substantially lowresistance conductor in the overburden casing with a centralizersupport.
 3725. The method of claim 3702, further comprising electricallycoupling a lead-in conductor to the first conductor, wherein the lead-inconductor comprises a low resistance conductor configured to generatesubstantially no heat.
 3726. The method of claim 3702, furthercomprising electrically coupling a lead-in conductor to the firstconductor, wherein the lead-in conductor comprises copper.
 3727. Themethod of claim 3702, further comprising maintaining a sufficientpressure between the first conduit and the formation to substantiallyinhibit deformation of the first conduit.
 3728. The method of claim3702, further comprising providing a thermally conductive fluid withinthe first conduit.
 3729. The method of claim 3702, further comprisingproviding a thermally conductive fluid within the first conduit, whereinthe thermally conductive fluid comprises helium.
 3730. The method ofclaim 3702, further comprising inhibiting arcing between the firstconductor and the first conduit with a fluid disposed within the firstconduit.
 3731. The method of claim 3702, further comprising removing avapor from the opening using a perforated tube disposed proximate to thefirst conduit in the opening to control a pressure in the opening. 3732.The method of claim 3702, further comprising flowing a corrosioninhibiting fluid through a perforated tube disposed proximate to thefirst conduit in the opening.
 3733. The method of claim 3702, wherein asecond conductor is disposed within the first conduit, wherein thesecond conductor is electrically coupled to the first conductor to forman electrical circuit.
 3734. The method of claim 3702, wherein a secondconductor is disposed within the first conduit, wherein the secondconductor is electrically coupled to the first conductor with aconnector.
 3735. The method of claim 3702, wherein a second conductor isdisposed within a second conduit and a third conductor is disposedwithin a third conduit, wherein the second conduit and the third conduitare disposed in different openings of the formation, wherein the firstconductor is electrically coupled to the second conductor and the thirdconductor, and wherein the first, second, and third conductors areconfigured to operate in a 3-phase Y configuration.
 3736. The method ofclaim 3702, wherein a second conductor is disposed within the firstconduit, wherein at least one sliding electrical connector is coupled tothe first conductor and the second conductor, and wherein heat generatedby at least the one sliding electrical connector is less than heatgenerated by the first conductor or the second conductor.
 3737. Themethod of claim 3702, wherein the first conduit comprises a firstsection and a second section, wherein a thickness of the first sectionis greater than a thickness of the second section such that heatradiated from the first conductor to the section along the first sectionof the conduit is less than heat radiated from the first conductor tothe section along the second section of the conduit.
 3738. The method ofclaim 3702, further comprising flowing an oxidizing fluid through anorifice in the first conduit.
 3739. The method of claim 3702, furthercomprising disposing a perforated tube proximate to the first conduitand flowing an oxidizing fluid through the perforated tube.
 3740. Themethod of claim 3702, further comprising heating at least the portion ofthe formation to substantially pyrolyze at least some hydrocarbonswithin the formation.
 3741. A system configured to heat an oil shaleformation, comprising: a first conductor disposed in a first conduit,wherein the first conduit is disposed within a first opening in theformation; a second conductor disposed in a second conduit, wherein thesecond conduit is disposed within a second opening in the formation; athird conductor disposed in a third conduit, wherein the third conduitis disposed within a third opening in the formation, wherein the first,second, and third conductors are electrically coupled in a 3-phase Yconfiguration, and wherein the first, second, and third conductors areconfigured to provide heat to at least a portion of the formation duringuse; and wherein the system is configured to allow heat to transfer fromthe first, second, and third conductors to a selected section of theformation during use.
 3742. The system of claim 3741, wherein the first,second, and third conductors are further configured to generate heatduring application of an electrical current to the first conductor.3743. The system of claim 3741, wherein the first, second, and thirdconductors comprise a pipe.
 3744. The system of claim 3741, wherein thefirst, second, and third conductors comprise stainless steel.
 3745. Thesystem of claim 3741, wherein the first, second, and third openingscomprise a diameter of at least approximately 5 cm.
 3746. The system ofclaim 3741, further comprising a first sliding electrical connectorcoupled to the first conductor and a second sliding electrical connectorcoupled to the second conductor and a third sliding electrical connectorcoupled to the third conductor.
 3747. The system of claim 3741, furthercomprising a first sliding electrical connector coupled to the firstconductor, wherein the first sliding electrical connector is furthercoupled to the first conduit.
 3748. The system of claim 3741, furthercomprising a second sliding electrical connector coupled to the secondconductor, wherein the second sliding electrical connector is furthercoupled to the second conduit.
 3749. The system of claim 3741, furthercomprising a third sliding electrical connector coupled to the thirdconductor, wherein the third sliding electrical connector is furthercoupled to the third conduit.
 3750. The system of claim 3741, whereineach of the first, second, and third conduits comprises a first sectionand a second section, wherein a thickness of the first section isgreater than a thickness of the second section such that heat radiatedfrom each of the first, second, and third conductors to the sectionalong the first section of each of the conduits is less than heatradiated from the first, second, and third conductors to the sectionalong the second section of each of the conduits.
 3751. The system ofclaim 3741, further comprising a fluid disposed within the first,second, and third conduits, wherein the fluid is configured to maintaina pressure within the first conduit to substantially inhibit deformationof the first, second, and third conduits during use.
 3752. The system ofclaim 3741, further comprising a thermally conductive fluid disposedwithin the first, second, and third conduits.
 3753. The system of claim3741, further comprising a thermally conductive fluid disposed withinthe first, second, and third conduits, wherein the thermally conductivefluid comprises helium.
 3754. The system of claim 3741, furthercomprising a fluid disposed within the first, second, and thirdconduits, wherein the fluid is configured to substantially inhibitarcing between the first, second, and third conductors and the first,second, and third conduits during use.
 3755. The system of claim 3741,further comprising at least one tube disposed within the first, second,and third openings external to the first, second, and third conduits,wherein at least the one tube is configured to remove vapor producedfrom at least the heated portion of the formation such that a pressurebalance is maintained between the first, second, and third conduits andthe first, second, and third openings to substantially inhibitdeformation of the first, second, and third conduits during use. 3756.The system of claim 3741, wherein the first, second, and thirdconductors are further configured to generate radiant heat ofapproximately 650 W/m to approximately 1650 W/m during use.
 3757. Thesystem of claim 3741, further comprising at least one overburden casingcoupled to the first, second, and third openings, wherein at least theone overburden casing is disposed in an overburden of the formation.3758. The system of claim 3741, further comprising at least oneoverburden casing coupled to the first, second, and third openings,wherein at least the one overburden casing is disposed in an overburdenof the formation, and wherein at least the one overburden casingcomprises steel.
 3759. The system of claim 3741, further comprising atleast one overburden casing coupled to the first, second, and thirdopenings, wherein at least the one overburden casing is disposed in anoverburden of the formation, and wherein at least the one overburdencasing is further disposed in cement.
 3760. The system of claim 3741,further comprising at least one overburden casing coupled to the first,second, and third openings, wherein at least the one overburden casingis disposed in an overburden of the formation, and wherein a packingmaterial is disposed at a junction of at least the one overburden casingand the first, second, and third openings.
 3761. The system of claim3741, further comprising at least one overburden casing coupled to thefirst, second, and third openings, wherein at least the one overburdencasing is disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of at least the one overburden casingand the first, second, and third openings, and wherein the packingmaterial is further configured to substantially inhibit a flow of fluidbetween the first, second, and third openings and at least the oneoverburden casing during use.
 3762. The system of claim 3741, whereinthe heated section of the formation is substantially pyrolyzed.
 3763. Asystem configurable to heat an oil shale formation, comprising: a firstconductor configurable to be disposed in a first conduit, wherein thefirst conduit is configurable to be disposed within a first opening inthe formation; a second conductor configurable to be disposed in asecond conduit, wherein the second conduit is configurable to bedisposed within a second opening in the formation; a third conductorconfigurable to be disposed in a third conduit, wherein the thirdconduit is configurable to be disposed within a third opening in theformation, wherein the first, second, and third conductors are furtherconfigurable to be electrically coupled in a 3-phase Y configuration,and wherein the first, second, and third conductors are furtherconfigurable to provide heat to at least a portion of the formationduring use; and wherein the system is configurable to allow heat totransfer from the first, second, and third conductors to a selectedsection of the formation during use.
 3764. The system of claim 3763,wherein the first, second, and third conductors are further configurableto generate heat during application of an electrical current to thefirst conductor.
 3765. The system of claim 3763, wherein the first,second, and third conductors comprise a pipe.
 3766. The system of claim3763, wherein the first, second, and third conductors comprise stainlesssteel.
 3767. The system of claim 3763, wherein each of the first,second, and third openings comprises a diameter of at leastapproximately 5 cm.
 3768. The system of claim 3763, further comprising afirst sliding electrical connector coupled to the first conductor and asecond sliding electrical connector coupled to the second conductor anda third sliding electrical connector coupled to the third conductor.3769. The system of claim 3763, further comprising a first slidingelectrical connector coupled to the first conductor, wherein the firstsliding electrical connector is further coupled to the first conduit.3770. The system of claim 3763, further comprising a second slidingelectrical connector coupled to the second conductor, wherein the secondsliding electrical connector is further coupled to the second conduit.3771. The system of claim 3763, further comprising a third slidingelectrical connector coupled to the third conductor, wherein the thirdsliding electrical connector is further coupled to the third conduit.3772. The system of claim 3763, wherein each of the first, second, andthird conduits comprises a first section and a second section, wherein athickness of the first section is greater than a thickness of the secondsection such that heat radiated from each of the first, second, andthird conductors to the section along the first section of each of theconduits is less than heat radiated from the first, second, and thirdconductors to the section along the second section of each of theconduits.
 3773. The system of claim 3763, further comprising a fluiddisposed within the first, second, and third conduits, wherein the fluidis configurable to maintain a pressure within the first conduit tosubstantially inhibit deformation of the first, second, and thirdconduits during use.
 3774. The system of claim 3763, further comprisinga thermally conductive fluid disposed within the first, second, andthird conduits.
 3775. The system of claim 3763, further comprising athermally conductive fluid disposed within the first, second, and thirdconduits, wherein the thermally conductive fluid comprises helium. 3776.The system of claim 3763, further comprising a fluid disposed within thefirst, second, and third conduits, wherein the fluid is configurable tosubstantially inhibit arcing between the first, second, and thirdconductors and the first, second, and third conduits during use. 3777.The system of claim 3763, further comprising at least one tube disposedwithin the first, second, and third openings external to the first,second, and third conduits, wherein at least the one tube isconfigurable to remove vapor produced from at least the heated portionof the formation such that a pressure balance is maintained between thefirst, second, and third conduits and the first, second, and thirdopenings to substantially inhibit deformation of the first, second, andthird conduits during use.
 3778. The system of claim 3763, wherein thefirst, second, and third conductors are further configurable to generateradiant heat of approximately 650 W/m to approximately 1650 W/m duringuse.
 3779. The system of claim 3763, further comprising at least oneoverburden casing coupled to the first, second, and third openings,wherein at least the one overburden casing is disposed in an overburdenof the formation.
 3780. The system of claim 3763, further comprising atleast one overburden casing coupled to the first, second, and thirdopenings, wherein at least the one overburden casing is disposed in anoverburden of the formation, and wherein at least the one overburdencasing comprises steel.
 3781. The system of claim 3763, furthercomprising at least one overburden casing coupled to the first, second,and third openings, wherein at least the one overburden casing isdisposed in an overburden of the formation, and wherein at least the oneoverburden casing is further disposed in cement.
 3782. The system ofclaim 3763, further comprising at least one overburden casing coupled tothe first, second, and third openings, wherein at least the oneoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of at least the oneoverburden casing and the first, second, and third openings.
 3783. Thesystem of claim 3763, further comprising at least one overburden casingcoupled to the first, second, and third openings, wherein at least theone overburden casing is disposed in an overburden of the formation,wherein a packing material is disposed at a junction of at least the oneoverburden casing and the first, second, and third openings, and whereinthe packing material is further configurable to substantially inhibit aflow of fluid between the first, second, and third openings and at leastthe one overburden casing during use.
 3784. The system of claim 3763,wherein the heated section of the formation is substantially pyrolyzed.3785. The system of claim 3763, wherein the system is configured to heatan oil shale formation, and wherein the system comprises: a firstconductor disposed in a first conduit, wherein the first conduit isdisposed within a first opening in the formation; a second conductordisposed in a second conduit, wherein the second conduit is disposedwithin a second opening in the formation; a third conductor disposed ina third conduit, wherein the third conduit is disposed within a thirdopening in the formation, wherein the first, second, and thirdconductors are electrically coupled in a 3-phase Y configuration, andwherein the first, second, and third conductors are configured toprovide heat to at least a portion of the formation during use; andwherein the system is configured to allow heat to transfer from thefirst, second, and third conductors to a selected section of theformation during use.
 3786. An in situ method for heating an oil shaleformation, comprising: applying an electrical current to a firstconductor to provide heat to at least a portion of the formation,wherein the first conductor is disposed in a first conduit, and whereinthe first conduit is disposed within a first opening in the formation;applying an electrical current to a second conductor to provide heat toat least a portion of the formation, wherein the second conductor isdisposed in a second conduit, and wherein the second conduit is disposedwithin a second opening in the formation; applying an electrical currentto a third conductor to provide heat to at least a portion of theformation, wherein the third conductor is disposed in a third conduit,and wherein the third conduit is disposed within a third opening in theformation; and allowing the heat to transfer from the first, second, andthird conductors to a selected section of the formation.
 3787. Themethod of claim 3786, wherein the first, second, and third conductorscomprise a pipe.
 3788. The method of claim 3786, wherein the first,second, and third conductors comprise stainless steel.
 3789. The methodof claim 3786, wherein the first, second, and third conduits comprisestainless steel.
 3790. The method of claim 3786, wherein the providedheat comprises approximately 650 W/m to approximately 1650 W/m. 3791.The method of claim 3786, further comprising determining a temperaturedistribution in the first, second, and third conduits using anelectromagnetic signal provided to the first, second, and thirdconduits.
 3792. The method of claim 3786, further comprising monitoringthe applied electrical current.
 3793. The method of claim 3786, furthercomprising monitoring a voltage applied to the first, second, and thirdconductors.
 3794. The method of claim 3786, further comprisingmonitoring a temperature in the first, second, and third conduits withat least one thermocouple.
 3795. The method of claim 3786, furthercomprising maintaining a sufficient pressure between the first, second,and third conduits and the first, second, and third openings tosubstantially inhibit deformation of the first, second, and thirdconduits.
 3796. The method of claim 3786, further comprising providing athermally conductive fluid within the first, second, and third conduits.3797. The method of claim 3786, further comprising providing a thermallyconductive fluid within the first, second, and third conduits, whereinthe thermally conductive fluid comprises helium.
 3798. The method ofclaim 3786, further comprising inhibiting arcing between the first,second, and third conductors and the first, second, and third conduitswith a fluid disposed within the first, second, and third conduits.3799. The method of claim 3786, further comprising removing a vapor fromthe first, second, and third openings using at least one perforated tubedisposed proximate to the first, second, and third conduits in thefirst, second, and third openings to control a pressure in the first,second, and third openings.
 3800. The method of claim 3786, wherein thefirst, second, and third conduits comprise a first section and a secondsection, wherein a thickness of the first section is greater than athickness of the second section such that heat radiated from the first,second, and third conductors to the section along the first section ofthe first, second, and third conduits is less than heat radiated fromthe first, second, and third conductors to the section along the secondsection of the first, second, and third conduits.
 3801. The method ofclaim 3786, further comprising flowing an oxidizing fluid through anorifice in the first, second, and third conduits.
 3802. The method ofclaim 3786, further comprising heating at least the portion of theformation to substantially pyrolyze at least some of the carbon withinthe formation.
 3803. A system configured to heat an oil shale formation,comprising: a first conductor disposed in a conduit, wherein the conduitis disposed within an opening in the formation; and a second conductordisposed in the conduit, wherein the second conductor is electricallycoupled to the first conductor with a connector, and wherein the firstand second conductors are configured to provide heat to at least aportion of the formation during use; and wherein the system isconfigured to allow heat to transfer from the first and secondconductors to a selected section of the formation during use.
 3804. Thesystem of claim 3803, wherein the first conductor is further configuredto generate heat during application of an electrical current to thefirst conductor.
 3805. The system of claim 3803, wherein the first andsecond conductors comprise a pipe.
 3806. The system of claim 3803,wherein the first and second conductors comprise stainless steel. 3807.The system of claim 3803, wherein the conduit comprises stainless steel.3808. The system of claim 3803, further comprising a centralizerconfigured to maintain a location of the first and second conductorswithin the conduit.
 3809. The system of claim 3803, further comprising acentralizer configured to maintain a location of the first and secondconductors within the conduit, wherein the centralizer comprises ceramicmaterial.
 3810. The system of claim 3803, further comprising acentralizer configured to maintain a location of the first and secondconductors within the conduit, wherein the centralizer comprises ceramicmaterial and stainless steel.
 3811. The system of claim 3803, whereinthe opening comprises a diameter of at least approximately 5 cm. 3812.The system of claim 3803, further comprising a lead-in conductor coupledto the first and second conductors, wherein the lead-in conductorcomprises a low resistance conductor configured to generatesubstantially no heat.
 3813. The system of claim 3803, furthercomprising a lead-in conductor coupled to the first and secondconductors, wherein the lead-in conductor comprises copper.
 3814. Thesystem of claim 3803, wherein the conduit comprises a first section anda second section, wherein a thickness of the first section is greaterthan a thickness of the second section such that heat radiated from thefirst conductor to the section along the first section of the conduit isless than heat radiated from the first conductor to the section alongthe second section of the conduit.
 3815. The system of claim 3803,further comprising a fluid disposed within the conduit, wherein thefluid is configured to maintain a pressure within the conduit tosubstantially inhibit deformation of the conduit during use.
 3816. Thesystem of claim 3803, further comprising a thermally conductive fluiddisposed within the conduit.
 3817. The system of claim 3803, furthercomprising a thermally conductive fluid disposed within the conduit,wherein the thermally conductive fluid comprises helium.
 3818. Thesystem of claim 3803, further comprising a fluid disposed within theconduit, wherein the fluid is configured to substantially inhibit arcingbetween the first and second conductors and the conduit during use.3819. The system of claim 3803, further comprising a tube disposedwithin the opening external to the conduit, wherein the tube isconfigured to remove vapor produced from at least the heated portion ofthe formation such that a pressure balance is maintained between theconduit and the opening to substantially inhibit deformation of theconduit during use.
 3820. The system of claim 3803, wherein the firstand second conductors are further configured to generate radiant heat ofapproximately 650 W/m to approximately 1650 W/m during use.
 3821. Thesystem of claim 3803, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 3822. The system of claim 3803, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3823. The system of claim 3803,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3824. Thesystem of claim 3803, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3825. The system ofclaim 3803, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis further configured to substantially inhibit a flow of fluid betweenthe opening and the overburden casing during use.
 3826. The system ofclaim 3803, wherein the heated section of the formation is substantiallypyrolyzed.
 3827. The system of claim 3803, wherein the system isconfigured to heat an oil shale formation, and wherein the systemcomprises: a first conductor disposed in a conduit, wherein the conduitis disposed within an opening in the formation; a second conductordisposed in the conduit, wherein the second conductor is electricallycoupled to the first conductor with a connector, and wherein the firstand second conductors are configured to provide heat to at least aportion of the formation during use; and wherein the system isconfigured to allow heat to transfer from the first and secondconductors to a selected section of the formation during use.
 3828. Asystem configurable to heat an oil shale formation, comprising: a firstconductor configurable to be disposed in a conduit, wherein the conduitis configurable to be disposed within an opening in the formation; and asecond conductor configurable to be disposed in the conduit, wherein thesecond conductor is configurable to be electrically coupled to the firstconductor with a connector, and wherein the first and second conductorsare further configurable to provide heat to at least a portion of theformation during use; and wherein the system is configurable to allowheat to transfer from the first and second conductors to a selectedsection of the formation during use.
 3829. The system of claim 3828,wherein the first conductor is further configurable to generate heatduring application of an electrical current to the first conductor.3830. The system of claim 3828, wherein the first and second conductorscomprise a pipe.
 3831. The system of claim 3828, wherein the first andsecond conductors comprise stainless steel.
 3832. The system of claim3828, wherein the conduit comprises stainless steel.
 3833. The system ofclaim 3828, further comprising a centralizer configurable to maintain alocation of the first and second conductors within the conduit. 3834.The system of claim 3828, further comprising a centralizer configurableto maintain a location of the first and second conductors within theconduit, wherein the centralizer comprises ceramic material.
 3835. Thesystem of claim 3828, further comprising a centralizer configurable tomaintain a location of the first and second conductors within theconduit, wherein the centralizer comprises ceramic material andstainless steel.
 3836. The system of claim 3828, wherein the openingcomprises a diameter of at least approximately 5 cm.
 3837. The system ofclaim 3828, further comprising a lead-in conductor coupled to the firstand second conductors, wherein the lead-in conductor comprises a lowresistance conductor configurable to generate substantially no heat.3838. The system of claim 3828, further comprising a lead-in conductorcoupled to the first and second conductors, wherein the lead-inconductor comprises copper.
 3839. The system of claim 3828, wherein theconduit comprises a first section and a second section, wherein athickness of the first section is greater than a thickness of the secondsection such that heat radiated from the first conductor to the sectionalong the first section of the conduit is less than heat radiated fromthe first conductor to the section along the second section of theconduit.
 3840. The system of claim 3828, further comprising a fluiddisposed within the conduit, wherein the fluid is configurable tomaintain a pressure within the conduit to substantially inhibitdeformation of the conduit during use.
 3841. The system of claim 3828,further comprising a thermally conductive fluid disposed within theconduit.
 3842. The system of claim 3828, further comprising a thermallyconductive fluid disposed within the conduit, wherein the thermallyconductive fluid comprises helium.
 3843. The system of claim 3828,further comprising a fluid disposed within the conduit, wherein thefluid is configurable to substantially inhibit arcing between the firstand second conductors and the conduit during use.
 3844. The system ofclaim 3828, further comprising a tube disposed within the openingexternal to the conduit, wherein the tube is configurable to removevapor produced from at least the heated portion of the formation suchthat a pressure balance is maintained between the conduit and theopening to substantially inhibit deformation of the conduit during use.3845. The system of claim 3828, wherein the first and second conductorsare further configurable to generate radiant heat of approximately 650W/m to approximately 1650 W/m during use.
 3846. The system of claim3828, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation.
 3847. The system of claim 3828, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3848. The system of claim 3828,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3849. Thesystem of claim 3828, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3850. The system ofclaim 3828, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis further configurable to substantially inhibit a flow of fluid betweenthe opening and the overburden casing during use.
 3851. The system ofclaim 3828, wherein the heated section of the formation is substantiallypyrolyzed.
 3852. An in situ method for heating an oil shale formation,comprising: applying an electrical current to at least two conductors toprovide heat to at least a portion of the formation, wherein at leastthe two conductors are disposed within a conduit, wherein the conduit isdisposed within an opening in the formation, and wherein at least thetwo conductors are electrically coupled with a connector; and allowingheat to transfer from at least the two conductors to a selected sectionof the formation.
 3853. The method of claim 3852, wherein at least thetwo conductors comprise a pipe.
 3854. The method of claim 3852, whereinat least the two conductors comprise stainless steel.
 3855. The methodof claim 3852, wherein the conduit comprises stainless steel.
 3856. Themethod of claim 3852, further comprising maintaining a location of atleast the two conductors in the conduit with a centralizer.
 3857. Themethod of claim 3852, further comprising maintaining a location of atleast the two conductors in the conduit with a centralizer, wherein thecentralizer comprises ceramic material.
 3858. The method of claim 3852,further comprising maintaining a location of at least the two conductorsin the conduit with a centralizer, wherein the centralizer comprisesceramic material and stainless steel.
 3859. The method of claim 3852,wherein the provided heat comprises approximately 650 W/m toapproximately 1650 W/m.
 3860. The method of claim 3852, furthercomprising determining a temperature distribution in the conduit usingan electromagnetic signal provided to the conduit.
 3861. The method ofclaim 3852, further comprising monitoring the applied electricalcurrent.
 3862. The method of claim 3852, further comprising monitoring avoltage applied to at least the two conductors.
 3863. The method ofclaim 3852, further comprising monitoring a temperature in the conduitwith at least one thermocouple.
 3864. The method of claim 3852, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3865.The method of claim 3852, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3866. The method of claim 3852, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing is further disposed in cement.
 3867. The method of claim 3852,further comprising coupling an overburden casing to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3868. The method of claim 3852, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the method further comprises inhibiting a flow of fluid betweenthe opening and the overburden casing with a packing material.
 3869. Themethod of claim 3852, further comprising maintaining a sufficientpressure between the conduit and the formation to substantially inhibitdeformation of the conduit.
 3870. The method of claim 3852, furthercomprising providing a thermally conductive fluid within the conduit.3871. The method of claim 3852, further comprising providing a thermallyconductive fluid within the conduit, wherein the thermally conductivefluid comprises helium.
 3872. The method of claim 3852, furthercomprising inhibiting arcing between at least the two conductors and theconduit with a fluid disposed within the conduit.
 3873. The method ofclaim 3852, further comprising removing a vapor from the opening using aperforated tube disposed proximate to the conduit in the opening tocontrol a pressure in the opening.
 3874. The method of claim 3852,further comprising flowing a corrosion inhibiting fluid through aperforated tube disposed proximate to the conduit in the opening. 3875.The method of claim 3852, wherein the conduit comprises a first sectionand a second section, wherein a thickness of the first section isgreater than a thickness of the second section such that heat radiatedfrom the first conductor to the section along the first section of theconduit is less than heat radiated from the first conductor to thesection along the second section of the conduit.
 3876. The method ofclaim 3852, further comprising flowing an oxidizing fluid through anorifice in the conduit.
 3877. The method of claim 3852, furthercomprising disposing a perforated tube proximate to the conduit andflowing an oxidizing fluid through the perforated tube.
 3878. The methodof claim 3852, further comprising heating at least the portion of theformation to substantially pyrolyze at least some hydrocarbons withinthe formation.
 3879. A system configured to heat an oil shale formation,comprising: at least one conductor disposed in a conduit, wherein theconduit is disposed within an opening in the formation, and wherein atleast the one conductor is configured to provide heat to at least afirst portion of the formation during use; at least one slidingconnector, wherein at least the one sliding connector is coupled to atleast the one conductor, wherein at least the one sliding connector isconfigured to provide heat during use, and wherein heat provided by atleast the one sliding connector is substantially less than the heatprovided by at least the one conductor during use; and wherein thesystem is configured to allow heat to transfer from at least the oneconductor to a section of the formation during use.
 3880. The system ofclaim 3879, wherein at least the one conductor is further configured togenerate heat during application of an electrical current to at leastthe one conductor.
 3881. The system of claim 3879, wherein at least theone conductor comprises a pipe.
 3882. The system of claim 3879, whereinat least the one conductor comprises stainless steel.
 3883. The systemof claim 3879, wherein the conduit comprises stainless steel.
 3884. Thesystem of claim 3879, further comprising a centralizer configured tomaintain a location of at least the one conductor within the conduit.3885. The system of claim 3879, further comprising a centralizerconfigured to maintain a location of at least the one conductor withinthe conduit, wherein the centralizer comprises ceramic material. 3886.The system of claim 3879, further comprising a centralizer configured tomaintain a location of at least the one conductor within the conduit,wherein the centralizer comprises ceramic material and stainless steel.3887. The system of claim 3879, wherein the opening comprises a diameterof at least approximately 5 cm.
 3888. The system of claim 3879, furthercomprising a lead-in conductor coupled to at least the one conductor,wherein the lead-in conductor comprises a low resistance conductorconfigured to generate substantially no heat.
 3889. The system of claim3879, further comprising a lead-in conductor coupled to at least the oneconductor, wherein the lead-in conductor comprises copper.
 3890. Thesystem of claim 3879, wherein the conduit comprises a first section anda second section, wherein a thickness of the first section is greaterthan a thickness of the second section such that heat radiated from thefirst conductor to the section along the first section of the conduit isless than heat radiated from the first conductor to the section alongthe second section of the conduit.
 3891. The system of claim 3879,further comprising a fluid disposed within the conduit, wherein thefluid is configured to maintain a pressure within the conduit tosubstantially inhibit deformation of the conduit during use.
 3892. Thesystem of claim 3879, further comprising a thermally conductive fluiddisposed within the conduit.
 3893. The system of claim 3879, furthercomprising a thermally conductive fluid disposed within the conduit,wherein the thermally conductive fluid comprises helium.
 3894. Thesystem of claim 3879, further comprising a fluid disposed within theconduit, wherein the fluid is configured to substantially inhibit arcingbetween at least the one conductor and the conduit during use.
 3895. Thesystem of claim 3879, further comprising a tube disposed within theopening external to the conduit, wherein the tube is configured toremove vapor produced from at least the heated portion of the formationsuch that a pressure balance is maintained between the conduit and theopening to substantially inhibit deformation of the conduit during use.3896. The system of claim 3879, wherein at least the one conductor isfurther configured to generate radiant heat of approximately 650 W/m toapproximately 1650 W/m during use.
 3897. The system of claim 3879,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation.3898. The system of claim 3879, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3899. The system of claim 3879, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3900. The system of claim 3879, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3901. The system of claim 3879, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material is further configuredto substantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 3902. The system of claim 3879, furthercomprising an overburden casing coupled to the opening and asubstantially low resistance conductor disposed within the overburdencasing, wherein the substantially low resistance conductor iselectrically coupled to at least the one conductor.
 3903. The system ofclaim 3879, further comprising an overburden casing coupled to theopening and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to at least the one conductor, and wherein thesubstantially low resistance conductor comprises carbon steel.
 3904. Thesystem of claim 3879, further comprising an overburden casing coupled tothe opening and a substantially low resistance conductor disposed withinthe overburden casing and a centralizer configured to support thesubstantially low resistance conductor within the overburden casing.3905. The system of claim 3879, wherein the heated section of theformation is substantially pyrolyzed.
 3906. A system configurable toheat an oil shale formation, comprising: at least one conductorconfigurable to be disposed in a conduit, wherein the conduit isconfigurable to be disposed within an opening in the formation, andwherein at least the one conductor is further configurable to provideheat to at least a first portion of the formation during use; at leastone sliding connector, wherein at least the one sliding connector isconfigurable to be coupled to at least the one conductor, wherein atleast the one sliding connector is further configurable to provide heatduring use, and wherein heat provided by at least the one slidingconnector is substantially less than the heat provided by at least theone conductor during use; and wherein the system is configurable toallow heat to transfer from at least the one conductor to a section ofthe formation during use.
 3907. The system of claim 3906, wherein atleast the one conductor is further configurable to generate heat duringapplication of an electrical current to at least the one conductor.3908. The system of claim 3906, wherein at least the one conductorcomprises a pipe.
 3909. The system of claim 3906, wherein at least theone conductor comprises stainless steel.
 3910. The system of claim 3906,wherein the conduit comprises stainless steel.
 3911. The system of claim3906, further comprising a centralizer configurable to maintain alocation of at least the one conductor within the conduit.
 3912. Thesystem of claim 3906, further comprising a centralizer configurable tomaintain a location of at least the one conductor within the conduit,wherein the centralizer comprises ceramic material.
 3913. The system ofclaim 3906, further comprising a centralizer configurable to maintain alocation of at least the one conductor within the conduit, wherein thecentralizer comprises ceramic material and stainless steel.
 3914. Thesystem of claim 3906, wherein the opening comprises a diameter of atleast approximately 5 cm.
 3915. The system of claim 3906, furthercomprising a lead-in conductor coupled to at least the one conductor,wherein the lead-in conductor comprises a low resistance conductorconfigurable to generate substantially no heat.
 3916. The system ofclaim 3906, further comprising a lead-in conductor coupled to at leastthe one conductor, wherein the lead-in conductor comprises copper. 3917.The system of claim 3906, wherein the conduit comprises a first sectionand a second section, wherein a thickness of the first section isgreater than a thickness of the second section such that heat radiatedfrom the first conductor to the section along the first section of theconduit is less than heat radiated from the first conductor to thesection along the second section of the conduit.
 3918. The system ofclaim 3906, further comprising a fluid disposed within the conduit,wherein the fluid is configurable to maintain a pressure within theconduit to substantially inhibit deformation of the conduit during use.3919. The system of claim 3906, further comprising a thermallyconductive fluid disposed within the conduit.
 3920. The system of claim3906, further comprising a thermally conductive fluid disposed withinthe conduit, wherein the thermally conductive fluid comprises helium.3921. The system of claim 3906, further comprising a fluid disposedwithin the conduit, wherein the fluid is configurable to substantiallyinhibit arcing between at least the one conductor and the conduit duringuse.
 3922. The system of claim 3906, further comprising a tube disposedwithin the opening external to the conduit, wherein the tube isconfigurable to remove vapor produced from at least the heated portionof the formation such that a pressure balance is maintained between theconduit and the opening to substantially inhibit deformation of theconduit during use.
 3923. The system of claim 3906, wherein at least theone conductor is further configurable to generate radiant heat ofapproximately 650 W/m to approximately 1650 W/m during use.
 3924. Thesystem of claim 3906, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 3925. The system of claim 3906, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3926. The system of claim 3906,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3927. Thesystem of claim 3906, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3928. The system ofclaim 3906, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis further configurable to substantially inhibit a flow of fluid betweenthe opening and the overburden casing during use.
 3929. The system ofclaim 3906, further comprising an overburden casing coupled to theopening and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to at least the one conductor.
 3930. The system ofclaim 3906, further comprising an overburden casing coupled to theopening and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to at least the one conductor, and wherein thesubstantially low resistance conductor comprises carbon steel.
 3931. Thesystem of claim 3906, further comprising an overburden casing coupled tothe opening and a substantially low resistance conductor disposed withinthe overburden casing and a centralizer configurable to support thesubstantially low resistance conductor within the overburden casing.3932. The system of claim 3906, wherein the heated section of theformation is substantially pyrolyzed.
 3933. The system of claim 3906,wherein the system is configured to heat an oil shale formation, andwherein the system comprises: at least one conductor disposed in aconduit, wherein the conduit is disposed within an opening in theformation, and wherein at least the one conductor is configured toprovide heat to at least a first portion of the formation during use; atleast one sliding connector, wherein at least the one sliding connectoris coupled to at least the one conductor, wherein at least the onesliding connector is configured to provide heat during use, and whereinheat provided by at least the one sliding connector is substantiallyless than the heat provided by at least the one conductor during use;and wherein the system is configured to allow heat to transfer from atleast the one conductor to a section of the formation during use. 3934.An in situ method for heating an oil shale formation, comprising:applying an electrical current to at least one conductor and at leastone sliding connector to provide heat to at least a portion of theformation, wherein at least the one conductor and at least the onesliding connector are disposed within a conduit, and wherein heatprovided by at least the one conductor is substantially greater thanheat provided by at least the one sliding connector; and allowing theheat to transfer from at least the one conductor and at least the onesliding connector to a section of the formation.
 3935. The method ofclaim 3934, wherein at least the one conductor comprises a pipe. 3936.The method of claim 3934, wherein at least the one conductor comprisesstainless steel.
 3937. The method of claim 3934, wherein the conduitcomprises stainless steel.
 3938. The method of claim 3934, furthercomprising maintaining a location of at least the one conductor in theconduit with a centralizer.
 3939. The method of claim 3934, furthercomprising maintaining a location of at least the one conductor in theconduit with a centralizer, wherein the centralizer comprises ceramicmaterial.
 3940. The method of claim 3934, further comprising maintaininga location of at least the one conductor in the conduit with acentralizer, wherein the centralizer comprises ceramic material andstainless steel.
 3941. The method of claim 3934, wherein the providedheat comprises approximately 650 W/m to approximately 1650 W/m. 3942.The method of claim 3934, further comprising determining a temperaturedistribution in the conduit using an electromagnetic signal provided tothe conduit.
 3943. The method of claim 3934, further comprisingmonitoring the applied electrical current.
 3944. The method of claim3934, further comprising monitoring a voltage applied to at least theone conductor.
 3945. The method of claim 3934, further comprisingmonitoring a temperature in the conduit with at least one thermocouple.3946. The method of claim 3934, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation.
 3947. The method of claim3934, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing comprises steel.
 3948. Themethod of claim 3934, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3949. The method of claim 3934, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3950. The method of claim 3934, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the method further comprises inhibiting a flow of fluid betweenthe opening and the overburden casing with a packing material.
 3951. Themethod of claim 3934, further comprising coupling an overburden casingto the opening, wherein a substantially low resistance conductor isdisposed within the overburden casing, and wherein the substantially lowresistance conductor is electrically coupled to at least the oneconductor.
 3952. The method of claim 3934, further comprising couplingan overburden casing to the opening, wherein a substantially lowresistance conductor is disposed within the overburden casing, whereinthe substantially low resistance conductor is electrically coupled to atleast the one conductor, and wherein the substantially low resistanceconductor comprises carbon steel.
 3953. The method of claim 3934,further comprising coupling an overburden casing to the opening, whereina substantially low resistance conductor is disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to at least the one conductor, and wherein themethod further comprises maintaining a location of the substantially lowresistance conductor in the overburden casing with a centralizersupport.
 3954. The method of claim 3934, further comprising electricallycoupling a lead-in conductor to at least the one conductor, wherein thelead-in conductor comprises a low resistance conductor configured togenerate substantially no heat.
 3955. The method of claim 3934, furthercomprising electrically coupling a lead-in conductor to at least the oneconductor, wherein the lead-in conductor comprises copper.
 3956. Themethod of claim 3934, further comprising maintaining a sufficientpressure between the conduit and the formation to substantially inhibitdeformation of the conduit.
 3957. The method of claim 3934, furthercomprising providing a thermally conductive fluid within the conduit.3958. The method of claim 3934, further comprising providing a thermallyconductive fluid within the conduit, wherein the thermally conductivefluid comprises helium.
 3959. The method of claim 3934, furthercomprising inhibiting arcing between the conductor and the conduit witha fluid disposed within the conduit.
 3960. The method of claim 3934,further comprising removing a vapor from the opening using a perforatedtube disposed proximate to the conduit in the opening to control apressure in the opening.
 3961. The method of claim 3934, furthercomprising flowing a corrosion inhibiting fluid through a perforatedtube disposed proximate to the conduit in the opening.
 3962. The methodof claim 3934, further comprising flowing an oxidizing fluid through anorifice in the conduit.
 3963. The method of claim 3934, furthercomprising disposing a perforated tube proximate to the conduit andflowing an oxidizing fluid through the perforated tube.
 3964. The methodof claim 3934, further comprising heating at least the portion of theformation to substantially pyrolyze at least some hydrocarbons withinthe formation.
 3965. A system configured to heat an oil shale formation,comprising: at least one elongated member disposed within an opening inthe formation, wherein at least the one elongated member is configuredto provide heat to at least a portion of the formation during use; andwherein the system is configured to allow heat to transfer from at leastthe one elongated member to a section of the formation during use. 3966.The system of claim 3965, wherein at least the one elongated membercomprises stainless steel.
 3967. The system of claim 3965, wherein atleast the one elongated member is further configured to generate heatduring application of an electrical current to at least the oneelongated member.
 3968. The system of claim 3965, further comprising asupport member coupled to at least the one elongated member, wherein thesupport member is configured to support at least the one elongatedmember.
 3969. The system of claim 3965, further comprising a supportmember coupled to at least the one elongated member, wherein the supportmember is configured to support at least the one elongated member, andwherein the support member comprises openings.
 3970. The system of claim3965, further comprising a support member coupled to at least the oneelongated member, wherein the support member is configured to support atleast the one elongated member, wherein the support member comprisesopenings, wherein the openings are configured to flow a fluid along alength of at least the one elongated member during use, and wherein thefluid is configured to substantially inhibit carbon deposition on orproximate to at least the one elongated member during use.
 3971. Thesystem of claim 3965, further comprising a tube disposed in the opening,wherein the tube comprises openings, wherein the openings are configuredto flow a fluid along a length of at least the one elongated memberduring use, and wherein the fluid is configured to substantially inhibitcarbon deposition on or proximate to at least the one elongated memberduring use.
 3972. The system of claim 3965, further comprising acentralizer coupled to at least the one elongated member, wherein thecentralizer is configured to electrically isolate at least the oneelongated member.
 3973. The system of claim 3965, further comprising acentralizer coupled to at least the one elongated member and a supportmember coupled to at least the one elongated member, wherein thecentralizer is configured to maintain a location of at least the oneelongated member on the support member.
 3974. The system of claim 3965,wherein the opening comprises a diameter of at least approximately 5 cm.3975. The system of claim 3965, further comprising a lead-in conductorcoupled to at least the one elongated member, wherein the lead-inconductor comprises a low resistance conductor configured to generatesubstantially no heat.
 3976. The system of claim 3965, furthercomprising a lead-in conductor coupled to at least the one elongatedmember, wherein the lead-in conductor comprises a rubber insulatedconductor.
 3977. The system of claim 3965, further comprising a lead-inconductor coupled to at least the one elongated member, wherein thelead-in conductor comprises copper wire.
 3978. The system of claim 3965,further comprising a lead-in conductor coupled to at least the oneelongated member with a cold pin transition conductor.
 3979. The systemof claim 3965, further comprising a lead-in conductor coupled to atleast the one elongated member with a cold pin transition conductor,wherein the cold pin transition conductor comprises a substantially lowresistance insulated conductor.
 3980. The system of claim 3965, whereinat least the one elongated member is arranged in a series electricalconfiguration.
 3981. The system of claim 3965, wherein at least the oneelongated member is arranged in a parallel electrical configuration.3982. The system of claim 3965, wherein at least the one elongatedmember is configured to generate radiant heat of approximately 650 W/mto approximately 1650 W/m during use.
 3983. The system of claim 3965,further comprising a perforated tube disposed in the opening external toat least the one elongated member, wherein the perforated tube isconfigured to remove vapor from the opening to control a pressure in theopening during use.
 3984. The system of claim 3965, further comprisingan overburden casing coupled to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 3985. The systemof claim 3965, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 3986.The system of claim 3965, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3987. The system of claim 3965, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3988. The system of claim 3965, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.3989. The system of claim 3965, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, wherein a packing material is disposed at ajunction of the overburden casing and the opening, and wherein thepacking material is further configured to substantially inhibit a flowof fluid between the opening and the overburden casing during use. 3990.The system of claim 3965, wherein the heated section of the formation issubstantially pyrolyzed.
 3991. A system configurable to heat an oilshale formation, comprising: at least one elongated member configurableto be disposed within an opening in the formation, wherein at least theone elongated member is further configurable to provide heat to at leasta portion of the formation during use; and wherein the system isconfigurable to allow heat to transfer from at least the one elongatedmember to a section of the formation during use.
 3992. The system ofclaim 3991, wherein at least the one elongated member comprisesstainless steel.
 3993. The system of claim 3991, wherein at least theone elongated member is further configurable to generate heat duringapplication of an electrical current to at least the one elongatedmember.
 3994. The system of claim 3991, further comprising a supportmember coupled to at least the one elongated member, wherein the supportmember is configurable to support at least the one elongated member.3995. The system of claim 3991, further comprising a support membercoupled to at least the one elongated member, wherein the support memberis configurable to support at least the one elongated member, andwherein the support member comprises openings.
 3996. The system of claim3991, further comprising a support member coupled to at least the oneelongated member, wherein the support member is configurable to supportat least the one elongated member, wherein the support member comprisesopenings, wherein the openings are configurable to flow a fluid along alength of at least the one elongated member during use, and wherein thefluid is configurable to substantially inhibit carbon deposition on orproximate to at least the one elongated member during use.
 3997. Thesystem of claim 3991, further comprising a tube disposed in the opening,wherein the tube comprises openings, wherein the openings areconfigurable to flow a fluid along a length of at least the oneelongated member during use, and wherein the fluid is configurable tosubstantially inhibit carbon deposition on or proximate to at least theone elongated member during use.
 3998. The system of claim 3991, furthercomprising a centralizer coupled to at least the one elongated member,wherein the centralizer is configurable to electrically isolate at leastthe one elongated member.
 3999. The system of claim 3991, furthercomprising a centralizer coupled to at least the one elongated memberand a support member coupled to at least the one elongated member,wherein the centralizer is configurable to maintain a location of atleast the one elongated member on the support member.
 4000. The systemof claim 3991, wherein the opening comprises a diameter of at leastapproximately 5 cm.
 4001. The system of claim 3991, further comprising alead-in conductor coupled to at least the one elongated member, whereinthe lead-in conductor comprises a low resistance conductor configurableto generate substantially no heat.
 4002. The system of claim 3991,further comprising a lead-in conductor coupled to at least the oneelongated member, wherein the lead-in conductor comprises a rubberinsulated conductor.
 4003. The system of claim 3991, further comprisinga lead-in conductor coupled to at least the one elongated member,wherein the lead-in conductor comprises copper wire.
 4004. The system ofclaim 3991, further comprising a lead-in conductor coupled to at leastthe one elongated member with a cold pin transition conductor.
 4005. Thesystem of claim 3991, further comprising a lead-in conductor coupled toat least the one elongated member with a cold pin transition conductor,wherein the cold pin transition conductor comprises a substantially lowresistance insulated conductor.
 4006. The system of claim 3991, whereinat least the one elongated member is arranged in a series electricalconfiguration.
 4007. The system of claim 3991, wherein at least the oneelongated member is arranged in a parallel electrical configuration.4008. The system of claim 3991, wherein at least the one elongatedmember is configurable to generate radiant heat of approximately 650 W/mto approximately 1650 W/m during use.
 4009. The system of claim 3991,further comprising a perforated tube disposed in the opening external toat least the one elongated member, wherein the perforated tube isconfigurable to remove vapor from the opening to control a pressure inthe opening during use.
 4010. The system of claim 3991, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 4011.The system of claim 3991, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 4012. The system of claim 3991, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 4013. The system of claim 3991, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 4014. The system of claim 3991, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.4015. The system of claim 3991, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, wherein a packing material is disposed at ajunction of the overburden casing and the opening, and wherein thepacking material is further configurable to substantially inhibit a flowof fluid between the opening and the overburden casing during use. 4016.The system of claim 3991, wherein the heated section of the formation issubstantially pyrolyzed.
 4017. The system of claim 3991, wherein thesystem is configured to heat an oil shale formation, and wherein thesystem comprises: at least one elongated member disposed within anopening in the formation, wherein at least the one elongated member isconfigured to provide heat to at least a portion of the formation duringuse; and wherein the system is configured to allow heat to transfer fromat least the one elongated member to a section of the formation duringuse.
 4018. An in situ method for heating an oil shale formation,comprising: applying an electrical current to at least one elongatedmember to provide heat to at least a portion of the formation, whereinat least the one elongated member is disposed within an opening of theformation; and allowing heat to transfer from at least the one elongatedmember to a section of the formation.
 4019. The method of claim 4018,wherein at least the one elongated member comprises a metal strip. 4020.The method of claim 4018, wherein at least the one elongated membercomprises a metal rod.
 4021. The method of claim 4018, wherein at leastthe one elongated member comprises stainless steel.
 4022. The method ofclaim 4018, further comprising supporting at least the one elongatedmember on a center support member.
 4023. The method of claim 4018,further comprising supporting at least the one elongated member on acenter support member, wherein the center support member comprises atube.
 4024. The method of claim 4018, further comprising electricallyisolating at least the one elongated member with a centralizer. 4025.The method of claim 4018, further comprising laterally sp acing at leastthe one elongated member with a centralizer.
 4026. The method of claim4018, further comprising electrically coupling at least the oneelongated member in a series configuration.
 4027. The method of claim4018, further comprising electrically coupling at least the oneelongated member in a parallel configuration.
 4028. The method of claim4018, wherein the provided heat comprises approximately 650 W/ m toapproximately 1650 W/m.
 4029. The method of claim 4018, furthercomprising determining a temperature distribution in at least the oneelongated member using an electromagnetic signal provided to at leastthe one elongated member.
 4030. The method of claim 4018, furthercomprising monitoring the applied electrical current.
 4031. The methodof claim 4018, further comprising monitoring a voltage applied to atleast the one elongated member.
 4032. The method of claim 4018, furthercomprising monitoring a temperature in at least the one elongated memberwith at least one thermocouple.
 4033. The method of claim 4018, furthercomprising supporting at least the one elongated member on a centersupport member, wherein the center support member comprises openings,the method further comprising flowing an oxidizing fluid through theopenings to substantially inhibit carbon deposition proximate to or onat least the one elongated member.
 4034. The method of claim 4018,further comprising flowing an oxidizing fluid through a tube disposedproximate to at least the one elongated member to substantially inhibitcarbon deposition proximate to or on at least the one elongated member.4035. The method of claim 4018, further comprising flowing an oxidizingfluid through an opening in at least the one elongated member tosubstantially inhibit carbon deposition proximate to or on at least theone elongated member.
 4036. The method of claim 4018, further comprisingelectrically coupling a lead-in conductor to at least the one elongatedmember, wherein the lead-in conductor comprises a low resistanceconductor configured to generate substantially no heat.
 4037. The methodof claim 4018, further comprising electrically coupling a lead-inconductor to at least the one elongated member using a cold pintransition conductor.
 4038. The method of claim 4018, further comprisingelectrically coupling a lead-in conductor to at least the one elongatedmember using a cold pin transition conductor, wherein the cold pintransition conductor comprises a substantially low resistance insulatedconductor.
 4039. The method of claim 4018, further comprising couplingan overburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation.
 4040. The method of claim4018, further comprising coupling an overburden casing to the opening,wherein the overburden casing comprises steel.
 4041. The method of claim4018, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in cement.
 4042. The method ofclaim 4018, further comprising coupling an overburden casing to theopening, wherein a packing material is disposed at a junction of theoverburden casing and the opening.
 4043. The method of claim 4018,further comprising coupling an overburden casing to the opening, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the method further comprises inhibiting aflow of fluid between the opening and the overburden casing with thepacking material.
 4044. The method of claim 4018, further comprisingheating at least the portion of the formation to substantially pyrolyzeat least some hydrocarbons within the formation.
 4045. A systemconfigured to heat an oil shale formation, comprising: at least oneelongated member disposed within an opening in the formation, wherein atleast the one elongated member is configured to provide heat to at leasta portion of the formation during use; an oxidizing fluid source; aconduit disposed within the opening, wherein the conduit is configuredto provide an oxidizing fluid from the oxidizing fluid source to theopening during use, and wherein the oxidizing fluid is selected tosubstantially inhibit carbon deposition on or proximate to at least theone elongated member during use; and wherein the system is configured toallow heat to transfer from at least the one elongated member to asection of the formation during use.
 4046. The system of claim 4045,wherein at least the one elongated member comprises stainless steel.4047. The system of claim 4045, wherein at least the one elongatedmember is further configured to generate heat during application of anelectrical current to at least the one elongated member.
 4048. Thesystem of claim 4045, wherein at least the one elongated member iscoupled to the conduit, wherein the conduit is further configured tosupport at least the one elongated member.
 4049. The system of claim4045, wherein at least the one elongated member is coupled to theconduit, wherein the conduit is further configured to support at leastthe one elongated member, and wherein the conduit comprises openings.4050. The system of claim 4045, further comprising a centralizer coupledto at least the one elongated member and the conduit, wherein thecentralizer is configured to electrically isolate at least the oneelongated member from the conduit.
 4051. The system of claim 4045,further comprising a centralizer coupled to at least the one elongatedmember and the conduit, wherein the centralizer is configured tomaintain a location of at least the one elongated member on the conduit.4052. The system of claim 4045, wherein the opening comprises a diameterof at least approximately 5 cm.
 4053. The system of claim 4045, furthercomprising a lead-in conductor coupled to at least the one elongatedmember, wherein the lead-in conductor comprises a low resistanceconductor configured to generate substantially no heat.
 4054. The systemof claim 4045, further comprising a lead-in conductor coupled to atleast the one elongated member, wherein the lead-in conductor comprisesa rubber insulated conductor.
 4055. The system of claim 4045, furthercomprising a lead-in conductor coupled to at least the one elongatedmember, wherein the lead-in conductor comprises copper wire.
 4056. Thesystem of claim 4045, further comprising a lead-in conductor coupled toat least the one elongated member with a cold pin transition conductor.4057. The system of claim 4045, further comprising a lead-in conductorcoupled to at least the one elongated member with a cold pin transitionconductor, wherein the cold pin transition conductor comprises asubstantially low resistance insulated conductor.
 4058. The system ofclaim 4045, wherein at least the one elongated member is arranged in aseries electrical configuration.
 4059. The system of claim 4045, whereinat least the one elongated member is arranged in a parallel electricalconfiguration.
 4060. The system of claim 4045, wherein at least the oneelongated member is configured to generate radiant heat of approximately650 W/m to approximately 1650 W/m during use.
 4061. The system of claim4045, further comprising a perforated tube disposed in the openingexternal to at least the one elongated member, wherein the perforatedtube is configured to remove vapor from the opening to control apressure in the opening during use.
 4062. The system of claim 4045,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation.4063. The system of claim 4045, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 4064. The system of claim 4045, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 4065. The system of claim 4045, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 4066. The system of claim 4045, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.4067. The system of claim 4045, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, wherein a packing material is disposed at ajunction of the overburden casing and the opening, and wherein thepacking material is further configured to substantially inhibit a flowof fluid between the opening and the overburden casing during use. 4068.The system of claim 4045, wherein the heated section of the formation issubstantially pyrolyzed.
 4069. A system configurable to heat an oilshale formation, comprising: at least one elongated member configurableto be disposed within an opening in the formation, wherein at least theone elongated member is further configurable to provide heat to at leasta portion of the formation during use; a conduit configurable to bedisposed within the opening, wherein the conduit is further configurableto provide an oxidizing fluid from the oxidizing fluid source to theopening during use, and wherein the system is configurable to allow theoxidizing fluid to substantially inhibit carbon deposition on orproximate to at least the one elongated member during use; and whereinthe system is further configurable to allow heat to transfer from atleast the one elongated member to a section of the formation during use.4070. The system of claim 4069, wherein at least the one elongatedmember comprises stainless steel.
 4071. The system of claim 4069,wherein at least the one elongated member is further configurable togenerate heat during application of an electrical current to at leastthe one elongated member.
 4072. The system of claim 4069, wherein atleast the one elongated member is coupled to the conduit, wherein theconduit is further configurable to support at least the one elongatedmember.
 4073. The system of claim 4069, wherein at least the oneelongated member is coupled to the conduit, wherein the conduit isfurther configurable to support at least the one elongated member, andwherein the conduit comprises openings.
 4074. The system of claim 4069,further comprising a centralizer coupled to at least the one elongatedmember and the conduit, wherein the centralizer is configurable toelectrically isolate at least the one elongated member from the conduit.4075. The system of claim 4069, further comprising a centralizer coupledto at least the one elongated member and the conduit, wherein thecentralizer is configurable to maintain a location of at least the oneelongated member on the conduit.
 4076. The system of claim 4069, whereinthe opening comprises a diameter of at least approximately 5 cm. 4077.The system of claim 4069, further comprising a lead-in conductor coupledto at least the one elongated member, wherein the lead-in conductorcomprises a low resistance conductor configurable to generatesubstantially no heat.
 4078. The system of claim 4069, furthercomprising a lead-in conductor coupled to at least the one elongatedmember, wherein the lead-in conductor comprises a rubber insulatedconductor.
 4079. The system of claim 4069, further comprising a lead-inconductor coupled to at least the one elongated member, wherein thelead-in conductor comprises copper wire.
 4080. The system of claim 4069,further comprising a lead-in conductor coupled to at least the oneelongated member with a cold pin transition conductor.
 4081. The systemof claim 4069, further comprising a lead-in conductor coupled to atleast the one elongated member with a cold pin transition conductor,wherein the cold pin transition conductor comprises a substantially lowresistance insulated conductor.
 4082. The system of claim 4069, whereinat least the one elongated member is arranged in a series electricalconfiguration.
 4083. The system of claim 4069, wherein at least the oneelongated member is arranged in a parallel electrical configuration.4084. The system of claim 4069, wherein at least the one elongatedmember is configurable to generate radiant heat of approximately 650 W/mto approximately 1650 W/m during use.
 4085. The system of claim 4069,further comprising a perforated tube disposed in the opening external toat least the one elongated member, wherein the perforated tube isconfigurable to remove vapor from the opening to control a pressure inthe opening during use.
 4086. The system of claim 4069, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 4087.The system of claim 4069, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 4088. The system of claim 4069, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 4089. The system of claim 4069, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 4090. The system of claim 4069, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.4091. The system of claim 4069, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, wherein a packing material is disposed at ajunction of the overburden casing and the opening, and wherein thepacking material is further configurable to substantially inhibit a flowof fluid between the opening and the overburden casing during use. 4092.The system of claim 4069, wherein the heated section of the formation issubstantially pyrolyzed.
 4093. The system of claim 4069, wherein thesystem is configured to heat an oil shale formation, and wherein thesystem comprises: at least one elongated member disposed within anopening in the formation, wherein at least the one elongated member isconfigured to provide heat to at least a portion of the formation duringuse; an oxidizing fluid source; a conduit disposed within the opening,wherein the conduit is configured to provide an oxidizing fluid from theoxidizing fluid source to the opening during use, and wherein theoxidizing fluid is selected to substantially inhibit carbon depositionon or proximate to at least the one elongated member during use; andwherein the system is configured to allow heat to transfer from at leastthe one elongated member to a section of the formation during use. 4094.An in situ method for heating an oil shale formation, comprising:applying an electrical current to at least one elongated member toprovide heat to at least a portion of the formation, wherein at leastthe one elongated member is disposed within an opening in the formation;providing an oxidizing fluid to at least the one elongated member tosubstantially inhibit carbon deposition on or proximate to at least theone elongated member; and allowing heat to transfer from at least theone elongated member to a section of the formation.
 4095. The method ofclaim 4094, wherein at least the one elongated member comprises a metalstrip.
 4096. The method of claim 4094, wherein at least the oneelongated member comprises a metal rod.
 4097. The method of claim 4094,wherein at least the one elongated member comprises stainless steel.4098. The method of claim 4094, further comprising supporting at leastthe one elongated member on a center support member.
 4099. The method ofclaim 4094, wherein comprising supporting at least the one elongatedmember on a center support member, wherein the center support membercomprises a tube.
 4100. The method of claim 4094, further comprisingelectrically isolating at least the one elongated member with acentralizer.
 4101. The method of claim 4094, further comprisinglaterally spacing at least the one elongated member with a centralizer.4102. The method of claim 4094, further comprising electrically couplingat least the one elongated member in a series configuration.
 4103. Themethod of claim 4094, further comprising electrically coupling at leastthe one elongated member in a parallel configuration.
 4104. The methodof claim 4094, wherein the provided heat comprises approximately 650 W/mto approximately 1650 W/m.
 4105. The method of claim 4094, furthercomprising determining a temperature distribution in at least the oneelongated member using an electromagnetic signal provided to at leastthe one elongated member.
 4106. The method of claim 4094, furthercomprising monitoring the applied electrical current.
 4107. The methodof claim 4094, further comprising monitoring a voltage applied to atleast the one elongated member.
 4108. The method of claim 4094, furthercomprising monitoring a temperature in at least the one elongated memberwith at least one thermocouple.
 4109. The method of claim 4094, furthercomprising supporting at least the one elongated member on a centersupport member, wherein the center support member comprises openings,wherein providing the oxidizing fluid to at least the one elongatedmember comprises flowing the oxidizing fluid through the openings in thecenter support member.
 4110. The method of claim 4094, wherein providingthe oxidizing fluid to at least the one elongated member comprisesflowing the oxidizing fluid through orifices in a tube disposed in theopening proximate to at least the one elongated member.
 4111. The methodof claim 4094, further comprising electrically coupling a lead-inconductor to at least the one elongated member, wherein the lead-inconductor comprises a low resistance conductor configured to generatesubstantially no heat.
 4112. The method of claim 4094, furthercomprising electrically coupling a lead-in conductor to at least the oneelongated member using a cold pin transition conductor.
 4113. The methodof claim 4094, further comprising electrically coupling a lead-inconductor to at least the one elongated member using a cold pintransition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 4114. Themethod of claim 4094, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 4115. The method of claim 4094, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing comprises steel.
 4116. The method of claim 4094,further comprising coupling an overburden casing to the opening, whereinthe overburden casing is disposed in cement.
 4117. The method of claim4094, further comprising coupling an overburden casing to the opening,wherein a packing material is disposed at a junction of the overburdencasing and the opening.
 4118. The method of claim 4094, furthercomprising coupling an overburden casing to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening, and wherein the method further comprises inhibiting a flowof fluid between the opening and the overburden casing with the packingmaterial.
 4119. The method of claim 4094, further comprising heating atleast the portion of the formation to substantially pyrolyze at leastsome hydrocarbons within the formation.
 4120. An in situ method forheating an oil shale formation, comprising: oxidizing a fuel fluid in aheater; providing at least a portion of the oxidized fuel fluid into aconduit disposed in an opening of the formation; allowing heat totransfer from the oxidized fuel fluid to a section of the formation; andallowing additional heat to transfer from an electric heater disposed inthe opening to the section of the formation, wherein heat is allowed totransfer substantially uniformly along a length of the opening. 4121.The method of claim 4120, wherein providing at least the portion of theoxidized fuel fluid into the opening comprises flowing the oxidized fuelfluid through a perforated conduit disposed in the opening.
 4122. Themethod of claim 4120, wherein providing at least the portion of theoxidized fuel fluid into the opening comprises flowing the oxidized fuelfluid through a perforated conduit disposed in the opening, the methodfurther comprising removing an exhaust fluid through the opening. 4123.The method of claim 4120, further comprising initiating oxidation of thefuel fluid in the heater with a flame.
 4124. The method of claim 4120,further comprising removing the oxidized fuel fluid through the conduit.4125. The method of claim 4120, further comprising removing the oxidizedfuel fluid through the conduit and providing the removed oxidized fuelfluid to at least one additional heater disposed in the formation. 4126.The method of claim 4120, wherein the conduit comprises an insulatordisposed on a surface of the conduit, the method further comprisingtapering a thickness of the insulator such that heat is allowed totransfer substantially uniformly along a length of the conduit. 4127.The method of claim 4120, wherein the electric heater is an insulatedconductor.
 4128. The method of claim 4120, wherein the electric heateris a conductor disposed in the conduit.
 4129. The method of claim 4120,wherein the electric heater is an elongated conductive member.
 4130. Asystem configured to heat an oil shale formation, comprising: one ormore heat sources disposed within one or more open wellbores in theformation, wherein the one or more heat sources are configured toprovide heat to at least a portion of the formation during use; andwherein the system is configured to allow heat to transfer from the oneor more heat sources to a selected section of the formation during use.4131. The system of claim 4130, wherein the one or more heat sourcescomprise at least two heat sources, and wherein superposition of heatfrom at least the two heat sources pyrolyzes at least some hydrocarbonswithin the selected section of the formation.
 4132. The system of claim4130, wherein the one or more heat sources comprise electrical heaters.4133. The system of claim 4130, wherein the one or more heat sourcescomprise surface burners.
 4134. The system of claim 4130, wherein theone or more heat sources comprise flameless distributed combustors.4135. The system of claim 4130, wherein the one or more heat sourcescomprise natural distributed combustors.
 4136. The system of claim 4130,wherein the one or more open wellbores comprise a diameter of at leastapproximately 5 cm.
 4137. The system of claim 4130, further comprisingan overburden casing coupled to at least one of the one or more openwellbores, wherein the overburden casing is disposed in an overburden ofthe formation.
 4138. The system of claim 4130, further comprising anoverburden casing coupled to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing comprises steel.
 4139. Thesystem of claim 4130, further comprising an overburden casing coupled toat least one of the one or more open wellbores, wherein the overburdencasing is disposed in an overburden of the formation, and wherein theoverburden casing is further disposed in cement.
 4140. The system ofclaim 4130, further comprising an overburden casing coupled to at leastone of the one or more open wellbores, wherein the overburden casing isdisposed in an overburden of the formation, and wherein a packingmaterial is disposed at a junction of the overburden casing and the atleast one of the one or more open wellbores.
 4141. The system of claim4130, further comprising an overburden casing coupled to at least one ofthe one or more open wellbores, wherein the overburden casing isdisposed in an overburden of the formation, wherein a packing materialis disposed at a junction of the overburden casing and the at least oneof the one or more open wellbores, and wherein the packing material isconfigured to substantially inhibit a flow of fluid between at least oneof the one or more open wellbores and the overburden casing during use.4142. The system of claim 4130, further comprising an overburden casingcoupled to at least one of the one or more open wellbores, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the at least one of the one or more open wellbores, and wherein thepacking material comprises cement.
 4143. The system of claim 4130,wherein the system is further configured to transfer heat such that thetransferred heat can pyrolyze at least some hydrocarbons in the selectedsection.
 4144. The system of claim 4130, further comprising a valvecoupled to at least one of the one or more heat sources configured tocontrol pressure within at least a majority of the selected section ofthe formation.
 4145. The system of claim 4130, further comprising avalve coupled to a production well configured to control a pressurewithin at least a majority of the selected section of the formation.4146. A method of treating an oil shale formation in situ, comprising:providing heat from one or more heat sources to at least one portion ofthe formation, wherein the one or more heat sources are disposed withinone or more open wellbores in the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; and producing a mixture from the formation.
 4147. The methodof claim 4146, wherein the one or more heat sources comprise at leasttwo heat sources, and wherein superposition of heat from at least thetwo heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 4148. The method of claim 4146,wherein controlling formation conditions comprises maintaining atemperature within the selected section within a pyrolysis temperaturerange with a lower pyrolysis temperature of about 250° C. and an upperpyrolysis temperature of about 400° C.
 4149. The method of claim 4146,wherein the one or more heat sources comprise electrical heaters. 4150.The method of claim 4146, wherein the one or more heat sources comprisesurface burners.
 4151. The method of claim 4146, wherein the one or moreheat sources comprise flameless distributed combustors.
 4152. The methodof claim 4146, wherein the one or more heat sources comprise naturaldistributed combustors.
 4153. The method of claim 4146, wherein the oneor more heat sources are suspended within the one or more openwellbores.
 4154. The method of claim 4146, wherein a tube is disposed inat least one of the one or more open wellbores proximate to the heatsource, the method further comprising flowing a substantially constantamount of fluid into at least one of the one or more open wellboresthrough critical flow orifices in the tube.
 4155. The method of claim4146, wherein a perforated tube is disposed in at least one of the oneor more open wellbores proximate to the heat source, the method furthercomprising flowing a corrosion inhibiting fluid into at least one of theopen wellbores through the perforated tube.
 4156. The method of claim4146, further comprising coupling an overburden casing to at least oneof the one or more open wellbores, wherein the overburden casing isdisposed in an overburden of the formation.
 4157. The method of claim4146, further comprising coupling an overburden casing to at least oneof the one or more open wellbores, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing comprises steel.
 4158. The method of claim 4146, furthercomprising coupling an overburden casing to at least one of the one ormore open wellbores, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 4159. The method of claim 4146, furthercomprising coupling an overburden casing to at least one of the one ormore open wellbores, wherein the overburden casing is disposed in anoverburden of the formation, and wherein a packing material is disposedat a junction of the overburden casing and the at least one of the oneor more open wellbores.
 4160. The method of claim 4146, furthercomprising coupling an overburden casing to at least one of the one ormore open wellbores, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the method further comprisesinhibiting a flow of fluid between the at least one of the one or moreopen wellbores and the overburden casing with a packing material. 4161.The method of claim 4146, further comprising heating at least theportion of the formation to substantially pyrolyze at least somehydrocarbons within the formation.
 4162. The method of claim 4146,further comprising controlling a pressure and a temperature within atleast a majority of the selected section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 4163. The method of claim 4146,further comprising controlling a pressure with the wellbore.
 4164. Themethod of claim 4146, further comprising controlling a pressure withinat least a majority of the selected section of the formation with avalve coupled to at least one of the one or more heat sources.
 4165. Themethod of claim 4146, further comprising controlling a pressure withinat least a majority of the selected section of the formation with avalve coupled to a production well located in the formation.
 4166. Themethod of claim 4146, further comprising controlling the heat such thatan average heating rate of the selected section is less than about 1° C.per day during pyrolysis.
 4167. The method of claim 4146, whereinproviding heat from the one or more heat sources to at least the portionof formation comprises: heating a selected volume (V) of the oil shaleformation from the one or more heat sources, wherein the formation hasan average heat capacity(C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 4168. The methodof claim 4146, wherein allowing the heat to transfer from the one ormore heat sources to the selected section comprises transferring heatsubstantially by conduction.
 4169. The method of claim 4146, whereinproviding heat from the one or more heat sources comprises heating theselected section such that a thermal conductivity of at least a portionof the selected section is greater than about 0.5 W/(m ° C.).
 4170. Themethod of claim 4146, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 4171. Themethod of claim 4146, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 4172. The method of claim4146, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.4173. The method of claim 4146, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 4174. Themethod of claim 4146, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 4175.The method of claim 4146, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 4176. The method of claim 4146, wherein the produced mixturecomprises condensable hydrocarbons, wherein about 5% by weight to about30% by weight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.4177. The method of claim 4146, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons issulfur.
 4178. The method of claim 4146, wherein the produced mixturecomprises condensable hydrocarbons, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 4179.The method of claim 4146, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 5% by weight ofthe condensable hydrocarbons comprises multi-ring aromatics with morethan two rings.
 4180. The method of claim 4146, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 4181.The method of claim 4146, wherein the produced mixture comprisescondensable hydrocarbons, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 4182. Themethod of claim 4146, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, and wherein the hydrogen is greater than about 10%by volume of the non-condensable component and wherein the hydrogen isless than about 80% by volume of the non-condensable component. 4183.The method of claim 4146, wherein the produced mixture comprisesammonia, and wherein greater than about 0.05% by weight of the producedmixture is ammonia.
 4184. The method of claim 4146, wherein the producedmixture comprises ammonia, and wherein the ammonia is used to producefertilizer.
 4185. The method of claim 4146, further comprisingcontrolling a pressure within at least a majority of the selectedsection of the formation.
 4186. The method of claim 4146, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 4187. The method of claim 4146, furthercomprising controlling formation conditions such that the producedmixture comprises a partial pressure of H₂ within the mixture greaterthan about 0.5 bars.
 4188. The method of claim 4187, wherein the partialpressure of H₂ is measured when the mixture is at a production well.4189. The method of claim 4146, wherein controlling formation conditionscomprises recirculating a portion of hydrogen from the mixture into theformation.
 4190. The method of claim 4146, further comprising altering apressure within the formation to inhibit production of hydrocarbons fromthe formation having carbon numbers greater than about
 25. 4191. Themethod of claim 4146, further comprising: providing hydrogen (H₂) to theheated section to hydrogenate hydrocarbons within the section; andheating a portion of the section with heat from hydrogenation.
 4192. Themethod of claim 4146, wherein the produced mixture comprises hydrogenand condensable hydrocarbons, the method further comprisinghydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 4193. The method of claim4146, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 4194. The method of claim 4146, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 4195. The method ofclaim 4146, further comprising controlling the heat to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured byFischer Assay.
 4196. The method of claim 4146, wherein producing themixture comprises producing the mixture in a production well, andwherein at least about 7 heat sources are disposed in the formation forthe production well.
 4197. The method of claim 4196, wherein at leastabout 20 heat sources are disposed in the formation for each productionwell.
 4198. The method of claim 4146, further comprising providing heatfrom three or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 4199. The method of claim 4146, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 4200. The method of claim 4146, furthercomprising separating the produced mixture into a gas stream and aliquid stream.
 4201. The method of claim 4146, further comprisingseparating the produced mixture into a gas stream and a liquid streamand separating the liquid stream into an aqueous stream and anon-aqueous stream.
 4202. The method of claim 4146, wherein the producedmixture comprises H₂S, the method further comprising separating aportion of the H₂S from non-condensable hydrocarbons.
 4203. The methodof claim 4146, wherein the produced mixture comprises CO₂, the methodfurther comprising separating a portion of the CO₂ from non-condensablehydrocarbons.
 4204. The method of claim 4146, wherein the mixture isproduced from a production well, wherein the heating is controlled suchthat the mixture can be produced from the formation as a vapor. 4205.The method of claim 4146, wherein the mixture is produced from aproduction well, the method further comprising heating a wellbore of theproduction well to inhibit condensation of the mixture within thewellbore.
 4206. The method of claim 4146, wherein the mixture isproduced from a production well, wherein a wellbore of the productionwell comprises a heater element configured to heat the formationadjacent to the wellbore, and further comprising heating the formationwith the heater element to produce the mixture, wherein the mixturecomprises a large non-condensable hydrocarbon gas component and H₂.4207. The method of claim 4146, wherein the selected section is heatedto a minimum pyrolysis temperature of about 270° C.
 4208. The method ofclaim 4146, further comprising maintaining the pressure within theformation above about 2.0 bars absolute to inhibit production of fluidshaving carbon numbers above
 25. 4209. The method of claim 4146, furthercomprising controlling pressure within the formation in a range fromabout atmospheric pressure to about 100 bars, as measured at a wellheadof a production well, to control an amount of condensable hydrocarbonswithin the produced mixture, wherein the pressure is reduced to increaseproduction of condensable hydrocarbons, and wherein the pressure isincreased to increase production of non-condensable hydrocarbons. 4210.The method of claim 4146, further comprising controlling pressure withinthe formation in a range from about atmospheric pressure to about 100bars, as measured at a wellhead of a production well, to control an APIgravity of condensable hydrocarbons within the produced mixture, whereinthe pressure is reduced to decrease the API gravity, and wherein thepressure is increased to reduce the API gravity.
 4211. A mixtureproduced from a portion of an oil shale formation, the mixturecomprising: an olefin content of less than about 10% by weight; and anaverage carbon number less than about
 35. 4212. The mixture of claim4211, further comprising an average carbon number less than about 30.4213. The mixture of claim 4211, further comprising an average carbonnumber less than about
 25. 4214. The mixture of claim 4211, furthercomprising: non-condensable hydrocarbons comprising hydrocarbons havingcarbon numbers of less than 5; and wherein a weight ratio of thehydrocarbons having carbon numbers from 2 through 4, to methane, in themixture is greater than approximately
 1. 4215. The mixture of claim4211, further comprising condensable hydrocarbons, wherein less thanabout 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen, wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen containing compounds, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 4216. The mixture of claim 4211, furthercomprising ammonia, wherein greater than about 0.05% by weight of theproduced mixture is ammonia.
 4217. The mixture of claim 4211, furthercomprising condensable hydrocarbons, wherein an olefin content of thecondensable hydrocarbons is greater than about 0.1% by weight of thecondensable hydrocarbons, and wherein the olefin content of thecondensable hydrocarbons is less than about 15% by weight of thecondensable hydrocarbons.
 4218. The mixture of claim 4211, furthercomprising condensable hydrocarbons, wherein less than about 15% byweight of the condensable hydrocarbons have a carbon number greater thanabout
 25. 4219. The mixture of claim 4218, wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen, wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons is oxygencontaining compounds, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons issulfur.
 4220. The mixture of claim 4211, further comprising condensablehydrocarbons, wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 4221. The mixture ofclaim 4211, further comprising: non-condensable hydrocarbons comprisinghydrocarbons having carbon numbers of less than about 5, wherein aweight ratio of the hydrocarbons having carbon number from 2 through 4,to methane, in the mixture is greater than approximately 1; wherein thenon-condensable hydrocarbons further comprise H₂, wherein greater thanabout 15% by weight of the non-condensable hydrocarbons comprises H₂;and condensable hydrocarbons, comprising: oxygenated hydrocarbons,wherein greater than about 1.5% by weight of the condensablehydrocarbons comprises oxygenated hydrocarbons; and aromatic compounds,wherein greater than about 20% by weight of the condensable hydrocarbonscomprises aromatic compounds.
 4222. The mixture of claim 4211, furthercomprising: condensable hydrocarbons, wherein less than about 5% byweight of the condensable hydrocarbons comprises hydrocarbons having acarbon number greater than about 25; wherein the condensablehydrocarbons further comprise: oxygenated hydrocarbons, wherein greaterthan about 5% by weight of the condensable hydrocarbons comprisesoxygenated hydrocarbons; and aromatic compounds, wherein greater thanabout 30% by weight of the condensable hydrocarbons comprises aromaticcompounds; and non-condensable hydrocarbons comprising H₂, whereingreater than about 15% by weight of the non-condensable hydrocarbonscomprises H₂.
 4223. The mixture of claim 4211, further comprisingcondensable hydrocarbons, comprising: olefins, wherein about 0.1% byweight to about 15% by weight of the condensable hydrocarbons comprisesolefins; and asphaltenes, wherein less than about 0.1% by weight of thecondensable hydrocarbons comprises asphaltenes.
 4224. The mixture ofclaim 4223, further comprising oxygenated hydrocarbons, wherein lessthan about 15% by weight of the condensable hydrocarbons comprisesoxygenated hydrocarbons.
 4225. The mixture of claim 4224, furthercomprising oxygenated hydrocarbons, wherein greater than about 5% byweight of the condensable hydrocarbons comprises oxygenatedhydrocarbons.
 4226. The mixture of claim 4211, further comprisingcondensable hydrocarbons, comprising: olefins, wherein about 0.1% byweight to about 2% by weight of the condensable hydrocarbons comprisesolefins; and multi-ring aromatics, wherein less than about 2% by weightof the condensable hydrocarbons comprises multi-ring aromatics with morethan two rings.
 4227. The mixture of claim 4211, further comprising:non-condensable hydrocarbons, wherein the non-condensable hydrocarbonscomprise H₂, wherein greater than about 10% by weight of thenon-condensable hydrocarbons comprises H₂; ammonia, wherein greater thanabout 0.5% by weight of the mixture comprises ammonia; and hydrocarbons,wherein a weight ratio of hydrocarbons having greater than about 2carbon atoms, to methane, is greater than about 0.4.
 4228. A mixtureproduced from a portion of an oil shale formation, the mixture,comprising: non-condensable hydrocarbons comprising hydrocarbons havingcarbon numbers of less than 5; and wherein a weight ratio of thehydrocarbons having carbon numbers from 2 through 4, to methane, in themixture is greater than approximately
 1. 4229. The mixture of claim4228, further comprising condensable hydrocarbons, wherein about 0.1% byweight to about 15% by weight of the condensable hydrocarbons areolefins.
 4230. The mixture of claim 4228, wherein a molar ratio ofethene to ethane in the non-condensable hydrocarbons ranges from about0.001 to about 0.15.
 4231. The mixture of claim 4228, further comprisingcondensable hydrocarbons, wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 4232. The mixture of claim 4228, further comprisingcondensable hydrocarbons, wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 4233. The mixture of claim 4228, further comprising condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 4234. Themixture of claim 4228, further comprising condensable hydrocarbons,wherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 4235. The mixture ofclaim 4228, further comprising condensable hydrocarbons, wherein greaterthan about 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 4236. The mixture of claim 4228, further comprisingcondensable hydrocarbons, wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 4237. The mixture of claim 4228, further comprisingcondensable hydrocarbons, wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 4238. The mixture of claim4228, further comprising condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons comprisecycloalkanes.
 4239. The mixture of claim 4228, wherein thenon-condensable hydrocarbons further comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablehydrocarbons, and wherein the hydrogen is less than about 80% by volumeof the non-condensable hydrocarbons.
 4240. The mixture of claim 4228,further comprising ammonia, wherein greater than about 0.05% by weightof the produced mixture is ammonia.
 4241. The mixture of claim 4228,further comprising ammonia, wherein the ammonia is used to producefertilizer.
 4242. The mixture of claim 4228, further comprisingcondensable hydrocarbons, wherein less than about 15 weight % of thecondensable hydrocarbons have a carbon number greater than approximately25.
 4243. The mixture of claim 4228, further comprising condensablehydrocarbons, wherein the condensable hydrocarbons comprise olefins, andwherein about 0.1% to about 5% by weight of the condensable hydrocarbonscomprises olefins.
 4244. The mixture of claim 4228, further comprisingcondensable hydrocarbons, wherein the condensable hydrocarbons comprisesolefins, and wherein about 0.1% to about 2.5% by weight of thecondensable hydrocarbons comprises olefins.
 4245. The mixture of claim4228, further comprising condensable hydrocarbons, wherein thecondensable hydrocarbons comprise oxygenated hydrocarbons, and whereingreater than about 5% by weight of the condensable hydrocarbonscomprises oxygenated hydrocarbons.
 4246. The mixture of claim 4228,further comprising non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise H₂, and wherein greater than about5% by weight of the non-condensable hydrocarbons comprises H₂.
 4247. Themixture of claim 4228, further comprising non-condensable hydrocarbons,wherein the non-condensable hydrocarbons comprise H₂, and whereingreater than about 15% by weight of the non-condensable hydrocarbonscomprises H₂.
 4248. The mixture of claim 4228, wherein a weight ratio ofhydrocarbons having greater than about 2 carbon atoms, to methane, isgreater than about 0.3.
 4249. A mixture produced from a portion of anoil shale formation, the mixture comprising: non-condensablehydrocarbons comprising hydrocarbons having carbon numbers of less than5, wherein a weight ratio of hydrocarbons having carbon numbers from 2through 4, to methane, is greater than approximately 1; and condensablehydrocarbons comprising oxygenated hydrocarbons, wherein greater thanabout 5% by weight of the condensable component comprises oxygenatedhydrocarbons.
 4250. The mixture of claim 4249, wherein about 0.1% byweight to about 15% by weight of the condensable hydrocarbons areolefins.
 4251. The mixture of claim 4249, wherein a molar ratio ofethene to ethane in the non-condensable hydrocarbons ranges from about0.001 to about 0.15.
 4252. The mixture of claim 4249, wherein less thanabout 1% by weight, when
 4253. The mixture of claim 4249, wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 4254. The mixture of claim 4249,wherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 4255. The mixture ofclaim 4249, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 4256. Themixture of claim 4249, wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 4257. The mixture ofclaim 4249, wherein less than about 5% by weight of the condensablehydrocarbons comprises multi-ring aromatics with more than two rings.4258. The mixture of claim 4249, wherein less than about 0.3% by weightof the condensable hydrocarbons are asphaltenes.
 4259. The mixture ofclaim 4249, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons are cycloalkanes.
 4260. The mixture of claim4249, wherein the non-condensable hydrocarbons comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable hydrocarbons, and wherein the hydrogen is less thanabout 80% by volume of the non-condensable hydrocarbons.
 4261. Themixture of claim 4249, wherein the produced mixture comprises ammonia,and wherein greater than about 0.05% by weight of the produced mixtureis ammonia.
 4262. The mixture of claim 4249, wherein the producedmixture comprises ammonia, and wherein the ammonia is used to producefertilizer.
 4263. The mixture of claim 4249, wherein less than about 5weight % of the condensable hydrocarbons in the mixture have a carbonnumber greater than approximately
 25. 4264. The mixture of claim 4249,wherein the condensable hydrocarbons further comprise olefins, andwherein about 0.1% to about 5% by weight of the condensable hydrocarbonscomprises olefins.
 4265. The mixture of claim 4249, wherein thecondensable hydrocarbons further comprise olefins, and wherein about0.1% to about 2.5% by weight of the condensable hydrocarbons comprisesolefins.
 4266. The mixture of claim 4249, wherein the non-condensablehydrocarbons further comprise H₂, wherein greater than about 5% byweight of the mixture comprises H₂.
 4267. The mixture of claim 4249,wherein the non-condensable hydrocarbons further comprise H₂, whereingreater than about 15% by weight of the mixture comprises H₂.
 4268. Themixture of claim 4249, wherein a weight ratio of hydrocarbons havinggreater than about 2 carbon atoms, to methane, is greater than about0.3.
 4269. A mixture produced from a portion of an oil shale formation,the mixture comprising: non-condensable hydrocarbons comprisinghydrocarbons having carbon numbers of less than 5, wherein a weightratio of hydrocarbons having carbon numbers from 2 through 4, tomethane, is greater than approximately 1; condensable hydrocarbons;wherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons comprises nitrogen; wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons comprises oxygen; and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons comprises sulfur.
 4270. The mixture of claim 4269, furthercomprising ammonia, wherein greater than about 0.05% by weight of theproduced mixture is ammonia.
 4271. The mixture of claim 4269, whereinless than about 5 weight % of the condensable hydrocarbons have a carbonnumber greater than approximately
 25. 4272. The mixture of claim 4269,wherein the condensable hydrocarbons comprise olefins, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 4273. The mixture of claim 4269, wherein a molar ratio ofethene to ethane in the non-condensable hydrocarbons ranges from about0.001 to about 0.15.
 4274. The mixture of claim 4269, wherein about 5%by weight to about 30% by weight of the condensable hydrocarbonscomprise oxygen containing compounds, and wherein the oxygen containingcompounds comprise phenols.
 4275. The mixture of claim 4269, whereingreater than about 20% by weight of the condensable hydrocarbons arearomatic compounds.
 4276. The mixture of claim 4269, wherein less thanabout 5% by weight of the condensable hydrocarbons comprises multi-ringaromatics with more than two rings.
 4277. The mixture of claim 4269,wherein less than about 0.3% by weight of the condensable hydrocarbonsare asphaltenes.
 4278. The mixture of claim 4269, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 4279. The mixture of claim 4269, wherein thenon-condensable hydrocarbons comprises hydrogen, and wherein thehydrogen is greater than about 10% by volume of the non-condensablehydrocarbons and wherein the hydrogen is less than about 80% by volumeof the non-condensable hydrocarbons.
 4280. The mixture of claim 4269,further comprising ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 4281. The mixture of claim4269, further comprising ammonia, and wherein the ammonia is used toproduce fertilizer.
 4282. The mixture of claim 4269, wherein thecondensable hydrocarbons comprises oxygenated hydrocarbons, and whereingreater than about 5% by weight of the condensable component comprisesoxygenated hydrocarbons.
 4283. The mixture of claim 4269, wherein thenon-condensable hydrocarbons comprise H₂, and wherein greater than about5% by weight of the non-condensable hydrocarbons comprises H₂.
 4284. Themixture of claim 4269, wherein the non-condensable hydrocarbons compriseH₂, and wherein greater than about 15% by weight of the mixturecomprises H₂.
 4285. The mixture of claim 4269, wherein a weight ratio ofhydrocarbons having greater than about 2 carbon atoms, to methane, isgreater, than about 0.3.
 4286. A mixture produced from a portion of anoil shale formation, the mixture comprising: non-condensablehydrocarbons comprising hydrocarbons having carbon numbers of less than5, wherein a weight ratio of hydrocarbons having carbon numbers from 2through 4, to methane, is greater than approximately 1; ammonia, whereingreater than about 0.5% by weight of the mixture comprises ammonia; andcondensable hydrocarbons comprising oxygenated hydrocarbons, whereingreater than about 5% by weight of the condensable hydrocarbonscomprises oxygenated hydrocarbons.
 4287. The mixture of claim 4286,wherein the condensable hydrocarbons further comprise olefins, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 4288. The mixture of claim 4286, wherein thenon-condensable hydrocarbons further comprise ethene and ethane, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 4289. The mixture ofclaim 4286, wherein the condensable hydrocarbons further comprisenitrogen containing compounds, and wherein less than about 1% by weight,when calculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 4290. The mixture of claim 4286, wherein the condensablehydrocarbons further comprise oxygen containing compounds, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 4291. The mixture of claim 4286,wherein the condensable hydrocarbons further comprise sulfur containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is sulfur.
 4292. Themixture of claim 4286, wherein the condensable hydrocarbons furthercomprise oxygen containing compounds, wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons comprise oxygencontaining compounds, and wherein the oxygen containing compoundscomprise phenols.
 4293. The mixture of claim 4286, wherein thecondensable hydrocarbons further comprise aromatic compounds, andwherein greater than about 20% by weight of the condensable hydrocarbonsare aromatic compounds.
 4294. The mixture of claim 4286, wherein thecondensable hydrocarbons further comprise multi-aromatic rings, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 4295. Themixture of claim 4286, wherein the condensable hydrocarbons furthercomprise asphaltenes, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 4296. The mixture of claim4286, wherein the condensable hydrocarbons further comprisecycloalkanes, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 4297. The mixture ofclaim 4286, wherein the non-condensable hydrocarbons further comprisehydrogen, wherein the hydrogen is greater than about 10% by volume ofthe non-condensable hydrocarbons, and wherein the hydrogen is less thanabout 80% by volume of the non-condensable hydrocarbons.
 4298. Themixture of claim 4286, wherein the produced mixture further comprisesammonia, and wherein greater than about 0.05% by weight of the producedmixture is ammonia.
 4299. The mixture of claim 4286, wherein theproduced mixture further comprises ammonia, and wherein the ammonia isused to produce fertilizer.
 4300. The mixture of claim 4286, wherein thecondensable hydrocarbons comprise hydrocarbons having a carbon number ofgreater than approximately 25, and wherein less than about 15 weight %of the hydrocarbons in the mixture have a carbon number greater thanapproximately
 25. 4301. The mixture of claim 4286, wherein thenon-condensable hydrocarbons further comprise H₂, and wherein greaterthan about 5% by weight of the mixture comprises H₂.
 4302. The mixtureof claim 4286, wherein the non-condensable hydrocarbons further compriseH₂, and wherein greater than about 15% by weight of the mixturecomprises H₂.
 4303. The mixture of claim 4286, wherein thenon-condensable hydrocarbons further comprise hydrocarbons having carbonnumbers of greater than 2, wherein a weight ratio of hydrocarbons havingcarbon numbers greater than 2, to methane, is greater than about 0.3.4304. A mixture produced from a portion of an oil shale formation, themixture comprising: non-condensable hydrocarbons comprising hydrocarbonshaving carbon numbers of less than 5, wherein a weight ratio ofhydrocarbons having carbon numbers from 2 through 4, to methane, isgreater than approximately 1; and condensable hydrocarbons comprisingolefins, wherein less than about 10% by weight of the condensablehydrocarbons comprises olefins.
 4305. The mixture of claim 4304, whereinthe non-condensable hydrocarbons further comprise ethene and ethane, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 4306. The mixture ofclaim 4304, wherein the condensable hydrocarbons further comprisenitrogen containing compounds, and wherein less than about 1% by weight,when calculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 4307. The mixture of claim 4304, wherein the condensablehydrocarbons further comprise oxygen containing compounds, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 4308. The mixture of claim 4304,wherein the condensable hydrocarbons further comprise sulfur containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is sulfur.
 4309. Themixture of claim 4304, wherein the condensable hydrocarbons furthercomprise oxygen containing compounds, wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons comprise oxygencontaining compounds, and wherein the oxygen containing compoundscomprise phenols.
 4310. The mixture of claim 4304, wherein thecondensable hydrocarbons further comprise aromatic compounds, andwherein greater than about 20% by weight of the condensable hydrocarbonsare aromatic compounds.
 4311. The mixture of claim 4304, wherein thecondensable hydrocarbons further comprise multi-ring aromatics, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 4312. Themixture of claim 4304, wherein the condensable hydrocarbons furthercomprise asphaltenes, and wherein less than about 0.3 % by weight of thecondensable hydrocarbons are asphaltenes.
 4313. The mixture of claim4304, wherein the condensable hydrocarbons further comprisecycloalkanes, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 4314. The mixture ofclaim 4304, wherein the non-condensable hydrocarbons further comprisehydrogen, and wherein the hydrogen is greater than about 10% by volumeof the non-condensable hydrocarbons and wherein the hydrogen is lessthan about 80% by volume of the non-condensable hydrocarbons.
 4315. Themixture of claim 4304, wherein the produced mixture further comprisesammonia, and wherein greater than about 0.05% by weight of the producedmixture is ammonia.
 4316. The mixture of claim 4304, wherein theproduced mixture further comprises ammonia, and wherein the ammonia isused to produce fertilizer.
 4317. The mixture of claim 4304, wherein thecondensable hydrocarbons further comprise hydrocarbons having a carbonnumber of greater than approximately 25, and wherein less than about 15%by weight of the hydrocarbons have a carbon number greater thanapproximately
 25. 4318. The mixture of claim 4304, wherein about 0.1% toabout 5% by weight of the condensable component comprises olefins. 4319.The mixture of claim 4304, wherein about 0.1% to about 2% by weight ofthe condensable component comprises olefins.
 4320. The mixture of claim4304, wherein the condensable hydrocarbons further comprise oxygenatedhydrocarbons, and wherein greater than about 5% by weight of thecondensable hydrocarbons comprises oxygenated hydrocarbons.
 4321. Themixture of claim 4304, wherein the condensable hydrocarbons furthercomprise oxygenated hydrocarbons, and wherein greater than about 25% byweight of the condensable component comprises oxygenated hydrocarbons.4322. The mixture of claim 4304, wherein the non-condensablehydrocarbons further comprise H₂, and wherein greater than about 5% byweight of the non-condensable hydrocarbons comprises H₂.
 4323. Themixture of claim 4304, wherein the non-condensable hydrocarbons furthercomprise H₂, and wherein greater than about 15% by weight of thenon-condensable hydrocarbons comprises H₂.
 4324. The mixture of claim4304, wherein a weight ratio of hydrocarbons having greater than about 2carbon atoms, to methane, is greater than about 0.3.
 4325. A mixtureproduced from a portion of an oil shale formation, comprising:condensable hydrocarbons, wherein less than about 15 weight % of thecondensable hydrocarbons have a carbon number greater than 25; andwherein the condensable hydrocarbons comprise oxygenated hydrocarbons,and wherein greater than about 5% by weight of the condensablehydrocarbons comprises oxygenated hydrocarbons.
 4326. The mixture ofclaim 4325, further comprising non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise hydrocarbons having carbon numbersof less than 5, and wherein a weight ratio of hydrocarbons having carbonnumbers from 2 through 4, to methane, is greater than approximately 1.4327. The mixture of claim 4325, wherein the condensable hydrocarbonsfurther comprise olefins, and wherein about 0.1% by weight to about 15%by weight of the condensable hydrocarbons are olefins.
 4328. The mixtureof claim 4325, further comprising non-condensable hydrocarbons, whereina molar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 4329. The mixture of claim 4325,wherein the condensable hydrocarbons further comprise nitrogencontaining compounds, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 4330. The mixture of claim 4325, wherein the condensablehydrocarbons further comprise oxygen containing compounds, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 4331. The mixture of claim 4325,wherein the condensable hydrocarbons further comprise sulfur containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is sulfur.
 4332. Themixture of claim 4325, wherein the condensable hydrocarbons furthercomprise oxygen containing compounds, wherein about 5% by weight toabout 1% by weight of the condensable hydrocarbons comprise oxygencontaining compounds, and wherein the oxygen containing compoundscomprise phenols.
 4333. The mixture of claim 4325, wherein thecondensable hydrocarbons further comprise aromatic compounds, andwherein greater than about 20% by weight of the condensable hydrocarbonsare aromatic compounds.
 4334. The mixture of claim 4325, wherein thecondensable hydrocarbons further comprise multi-ring aromatics, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 4335. Themixture of claim 4325, wherein the condensable hydrocarbons furthercomprise asphaltenes, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 4336. The mixture of claim4325, wherein the condensable hydrocarbons further comprisecycloalkanes, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 4337. The mixture ofclaim 4325, further comprising non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise hydrogen, and wherein the hydrogenis greater than about 10% by volume of the non-condensable hydrocarbonsand wherein the hydrogen is less than about 80% by volume of thenon-condensable hydrocarbons.
 4338. The mixture of claim 4325, furthercomprising ammonia, and wherein greater than about 0.05% by weight ofthe produced mixture is ammonia.
 4339. The mixture of claim 4325,further comprising ammonia, and wherein the ammonia is used to producefertilizer.
 4340. The mixture of claim 4325, wherein the condensablehydrocarbons further comprises olefins, and wherein less than about 10%by weight of the condensable hydrocarbons comprises olefins.
 4341. Themixture of claim 4325, wherein the condensable hydrocarbons furthercomprises olefins, and wherein about 0.1% to about 5% by weight of thecondensable hydrocarbons comprises olefins.
 4342. The mixture of claim4325, wherein the condensable hydrocarbons further comprises olefins,and wherein about 0.1% to about 2% by weight of the condensablehydrocarbons comprises olefins.
 4343. The mixture of claim 4325, whereinthe condensable hydrocarbons further comprises oxygenated hydrocarbons,and wherein greater than about 5% by weight of the condensablehydrocarbons comprises the oxygenated hydrocarbon.
 4344. The mixture ofclaim 4325, further comprising non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise H₂, wherein greater than about 5%by weight of the non-condensable hydrocarbons comprises H₂.
 4345. Themixture of claim 4325, further comprising non-condensable hydrocarbons,wherein the non-condensable hydrocarbons comprise H₂, wherein greaterthan about 15% by weight of the non-condensable hydrocarbons comprisesH₂.
 4346. The mixture of claim 4325, wherein a weight ratio ofhydrocarbons having greater than about 2 carbon atoms, to methane, isgreater than about 0.3.
 4347. A mixture produced from a portion of anoil shale formation, comprising: condensable hydrocarbons, wherein lessthan about 15% by weight of the condensable hydrocarbons have a carbonnumber greater than about 25; wherein less than about 1% by weight ofthe condensable hydrocarbons, when calculated on an atomic basis, isnitrogen; wherein less than about 1% by weight of the condensablehydrocarbons, when calculated on an atomic basis, is oxygen; and whereinless than about 1% by weight of the condensable hydrocarbons, whencalculated on an atomic basis, is sulfur.
 4348. The mixture of claim4347, further comprising non-condensable hydrocarbons, wherein thenon-condensable component comprises hydrocarbons having carbon numbersof less than 5, and wherein a weight ratio of hydrocarbons having carbonnumbers from 2 through 4, to methane, is greater than approximately 1.4349. The mixture of claim 4347, wherein the condensable hydrocarbonsfurther comprise olefins, and wherein about 0.1% by weight to about 15%by weight of the condensable hydrocarbons are olefins.
 4350. The mixtureof claim 4347, further comprising non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 4351. The mixture ofclaim 4347, wherein the condensable hydrocarbons further comprise oxygencontaining compounds, wherein about 5% by weight to about 30% by weightof the condensable hydrocarbons comprise oxygen containing compounds,and wherein the oxygen containing compounds comprise phenols.
 4352. Themixture of claim 4347, wherein the condensable hydrocarbons furthercomprise aromatic compounds, and wherein greater than about 20% byweight of the condensable hydrocarbons are aromatic compounds.
 4353. Themixture of claim 4347, wherein the condensable hydrocarbons furthercomprise multi-ring aromatics, and wherein less than about 5% by weightof the condensable hydrocarbons comprises multi-ring aromatics with morethan two rings.
 4354. The mixture of claim 4347, wherein the condensablehydrocarbons further comprise asphaltenes, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 4355.The mixture of claim 4347, wherein the condensable hydrocarbons furthercomprise cycloalkanes, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 4356. Themixture of claim 4347, further comprising non-condensable hydrocarbons,and wherein the non-condensable hydrocarbons comprise hydrogen, andwherein greater than about 10% by volume and less than about 80% byvolume of the non-condensable component comprises hydrogen.
 4357. Themixture of claim 4347, further comprising ammonia, and wherein greaterthan about 0.05% by weight of the produced mixture is ammonia.
 4358. Themixture of claim 4347, further comprising ammonia, and wherein theammonia is used to produce fertilizer.
 4359. The mixture of claim 4347,wherein the condensable component further comprises olefins, and whereinabout 0.1% to about 5% by weight of the condensable component comprisesolefins.
 4360. The mixture of claim 4347, wherein the condensablecomponent further comprises olefins, and wherein about 0.1% to about2.5% by weight of the condensable component comprises olefins.
 4361. Themixture of claim 4347, wherein the condensable hydrocarbons furthercomprise oxygenated hydrocarbons, and wherein greater than about 5% byweight of the condensable hydrocarbons comprises oxygenatedhydrocarbons.
 4362. The mixture of claim 4347, further comprisingnon-condensable hydrocarbons, wherein the non-condensable hydrocarbonscomprise H₂, and wherein greater than about 5% by weight of thenon-condensable hydrocarbons comprises H₂.
 4363. The mixture of claim4347, further comprising non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise H₂, and wherein greater than about15% by weight of the non-condensable hydrocarbons comprises H₂. 4364.The mixture of claim 4347, further comprising non-condensablehydrocarbons, wherein a weight ratio of compounds within thenon-condensable hydrocarbons having greater than about 2 carbon atoms,to methane, is greater than about 0.3.
 4365. A mixture produced from aportion of an oil shale formation, comprising: condensable hydrocarbons,wherein less than about 15% by weight of the condensable hydrocarbonshave a carbon number greater than 20; and wherein the condensablehydrocarbons comprise olefins, wherein an olefin content of thecondensable component is less than about 10% by weight of thecondensable component.
 4366. The mixture of claim 4365, furthercomprising non-condensable hydrocarbons, wherein the non-condensablehydrocarbons comprise hydrocarbons having carbon numbers of less than 5,and wherein a weight ratio of hydrocarbons having carbon numbers from 2through 4, to methane, is greater than approximately
 1. 4367. Themixture of claim 4365, wherein the condensable hydrocarbons furthercomprise olefins, and wherein about 0.1% by weight to about 15% byweight of the condensable hydrocarbons are olefins.
 4368. The mixture ofclaim 4365, further comprising non-condensable hydrocarbons, and whereina molar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 4369. The mixture of claim 4365,wherein the condensable hydrocarbons further comprise nitrogencontaining compounds, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 4370. The mixture of claim 4365, wherein the condensablehydrocarbons further comprise oxygen containing compounds, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 4371. The mixture of claim 4365,wherein the condensable hydrocarbons further comprise sulfur containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is sulfur.
 4372. Themixture of claim 4365, wherein the condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 4373. The mixture of claim4365, wherein the condensable hydrocarbons further comprise aromaticcompounds, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 4374. The mixture ofclaim 4365, wherein the condensable hydrocarbons further comprisemulti-ring aromatics, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 4375. The mixture of claim 4365, wherein the condensablehydrocarbons further comprise asphaltenes, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 4376.The mixture of claim 4365, wherein the condensable hydrocarbons furthercomprise cycloalkanes, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 4377. Themixture of claim 4365, further comprising non-condensable hydrocarbons,wherein the non-condensable hydrocarbons comprises hydrogen, and whereinthe hydrogen is about 10% by volume to about 80% by volume of thenon-condensable hydrocarbons.
 4378. The mixture of claim 4365, furthercomprising ammonia, wherein greater than about 0.05% by weight of theproduced mixture is ammonia.
 4379. The mixture of claim 4365, furthercomprising ammonia, and wherein the ammonia is used to producefertilizer.
 4380. The mixture of claim 4365, wherein about 0.1% to about5% by weight of the condensable component comprises olefins.
 4381. Themixture of claim 4365, wherein about 0.1% to about 2% by weight of thecondensable component comprises olefins.
 4382. The mixture of claim4365, wherein the condensable component further comprises oxygenatedhydrocarbons, and wherein greater than about 1.5% by weight of thecondensable component comprises oxygenated hydrocarbons.
 4383. Themixture of claim 4365, wherein the condensable component furthercomprises oxygenated hydrocarbons, and wherein greater than about 25% byweight of the condensable component comprises oxygenated hydrocarbons.4384. The mixture of claim 4365, further comprising non-condensablehydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, andwherein greater than about 5% by weight of the non-condensablehydrocarbons comprises H₂.
 4385. The mixture of claim 4365, furthercomprising non-condensable hydrocarbons, wherein the non-condensablehydrocarbons comprise H₂, and wherein greater than about 15% by weightof the non-condensable hydrocarbons comprises H₂.
 4386. The mixture ofclaim 4365, further comprising non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise hydrocarbons having carbon numbersof less than 5, and wherein a weight ratio of hydrocarbons having carbonnumbers from 2 through 4, to methane, is greater than approximately 0.3.4387. A mixture produced from a portion of an oil shale formation,comprising: condensable hydrocarbons, wherein less than about 5% byweight of the condensable hydrocarbons comprises hydrocarbons having acarbon number greater than about 25; and wherein the condensablehydrocarbons further comprise aromatic compounds, wherein more thanabout 20% by weight of the condensable hydrocarbons comprises aromaticcompounds.
 4388. The mixture of claim 4387, further comprisingnon-condensable hydrocarbons, wherein the non-condensable hydrocarbonscomprise hydrocarbons having carbon numbers of less than 5, and whereina weight ratio of hydrocarbons having carbon numbers from 2 through 4,to methane, is greater than approximately
 1. 4389. The mixture of claim4387, wherein the condensable hydrocarbons further comprise olefins, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 4390. The mixture of claim 4387, furthercomprising non-condensable hydrocarbons, wherein a molar ratio of etheneto ethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 4391. The mixture of claim 4387, wherein the condensablehydrocarbons further comprise nitrogen containing compounds, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 4392. The mixture of claim 4387,wherein the condensable hydrocarbons further comprise oxygen containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is oxygen.
 4393. Themixture of claim 4387, wherein the condensable hydrocarbons furthercomprise sulfur containing compounds, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 4394. The mixture of claim 4387, wherein thecondensable hydrocarbons further comprise oxygen containing compounds,wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 4395. The mixture of claim4387, wherein the condensable hydrocarbons further comprise multi-ringaromatics, and wherein less than about 5% by weight of the condensablehydrocarbons comprises multi-ring aromatics with more than two rings.4396. The mixture of claim 4387, wherein the condensable hydrocarbonsfurther comprise asphaltenes, and wherein less than about 0.3% by weightof the condensable hydrocarbons are asphaltenes.
 4397. The mixture ofclaim 4387, wherein the condensable hydrocarbons comprise cycloalkanes,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 4398. The mixture of claim 4387, furthercomprising non-condensable hydrocarbons, wherein the non-condensablehydrocarbons comprise hydrogen, and wherein the hydrogen is greater thanabout 10% by volume and less than about 80% by volume of thenon-condensable hydrocarbons.
 4399. The mixture of claim 4387, furthercomprising ammonia, and wherein greater than about 0.05% by weight ofthe produced mixture is ammonia.
 4400. The mixture of claim 4387,further comprising ammonia, and wherein the ammonia is used to producefertilizer.
 4401. The mixture of claim 4387, wherein the condensablehydrocarbons further comprise olefins, and wherein about 0.1% to about5% by weight of the condensable hydrocarbons comprises olefins. 4402.The mixture of claim 4387, wherein the condensable hydrocarbons furthercomprises olefins, and wherein about 0.1% to about 2% by weight of thecondensable hydrocarbons comprises olefins.
 4403. The mixture of claim4387, wherein the condensable hydrocarbons further comprises multi-ringaromatic compounds, and wherein less than about 2% by weight of thecondensable hydrocarbons comprises multi-ring aromatic compounds. 4404.The mixture of claim 4387, wherein the condensable hydrocarbonscomprises oxygenated hydrocarbons, and wherein greater than about 1.5%by weight of the condensable hydrocarbons comprises oxygenatedhydrocarbons.
 4405. The mixture of claim 4387, wherein the condensablehydrocarbons comprises oxygenated hydrocarbons, and wherein greater thanabout 25% by weight of the condensable component comprises oxygenatedhydrocarbons.
 4406. The mixture of claim 4387, further comprisingnon-condensable hydrocarbons, wherein the non-condensable hydrocarbonscomprise H₂, and wherein greater than about 5% by weight of thenon-condensable hydrocarbons comprises H₂.
 4407. The mixture of claim4387, further comprising non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise H₂, and wherein greater than about15% by weight of the non-condensable hydrocarbons comprises H₂. 4408.The mixture of claim 4387, further comprising non-condensablehydrocarbons, wherein the non-condensable hydrocarbons compriseshydrocarbons having carbon numbers of less than 5, and wherein a weightratio of hydrocarbons having carbon numbers from 2 through 4, tomethane, is greater than approximately 0.3.
 4409. A mixture producedfrom a portion of an oil shale formation, comprising: non-condensablehydrocarbons comprising hydrocarbons having carbon numbers of less thanabout 5, wherein a weight ratio of the hydrocarbons having carbon numberfrom 2 through 4, to methane, in the mixture is greater thanapproximately 1; wherein the non-condensable hydrocarbons furthercomprise H₂, wherein greater than about 15% by weight of thenon-condensable hydrocarbons comprises H₂; and condensable hydrocarbons,comprising: oxygenated hydrocarbons, wherein greater than about 1.5% byweight of the condensable hydrocarbons comprises oxygenatedhydrocarbons; olefins, wherein less than about 10% by weight of thecondensable hydrocarbons comprises olefins; and aromatic compounds,wherein greater than about 20% by weight of the condensable hydrocarbonscomprises aromatic compounds.
 4410. The mixture of claim 4409, whereinthe non-condensable hydrocarbons further comprise ethene and ethane, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001% to about 0.15.
 4411. The mixtureof claim 4409, wherein the condensable hydrocarbons further comprisenitrogen containing compounds, and wherein less than about 1% by weight,when calculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 4412. The mixture of claim 4409, wherein the condensablehydrocarbons further comprise oxygen containing compounds, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 4413. The mixture of claim 4409,wherein the condensable hydrocarbons further comprise sulfur containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is sulfur.
 4414. Themixture of claim 4409, wherein the condensable hydrocarbons furthercomprise oxygen containing compounds, wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons comprise oxygencontaining compounds, and wherein the oxygen containing compoundscomprise phenols.
 4415. The mixture of claim 4409, wherein thecondensable hydrocarbons comprise multi-ring aromatics, and wherein lessthan about 5% by weight of the condensable hydrocarbons comprisesmulti-ring aromatics with more than two rings
 4416. The mixture of claim4409, wherein the condensable hydrocarbons comprise asphaltenes, andwherein less than about 0.3% by weight of the condensable hydrocarbonsare asphaltenes.
 4417. The mixture of claim 4409, wherein thecondensable hydrocarbons comprise cycloalkanes, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 4418. The mixture of claim 4409, wherein thenon-condensable hydrocarbons further comprises hydrogen, and wherein thehydrogen is greater than about 10% by volume and less than about 80% byvolume of the non-condensable hydrocarbons.
 4419. The mixture of claim4409, further comprising ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 4420. The mixture of claim4409, further comprising ammonia, and wherein the ammonia is used toproduce fertilizer.
 4421. The mixture of claim 4409, wherein thecondensable hydrocarbons further comprise hydrocarbons having a carbonnumber of greater than approximately 25, wherein less than about 15% byweight of the hydrocarbons have a carbon number greater thanapproximately
 25. 4422. The mixture of claim 4409, wherein about 0.1% toabout 5% by weight of the condensable hydrocarbons comprises olefins.4423. The mixture of claim 4409, wherein about 0.1% to about 2% byweight of the condensable hydrocarbons comprises olefins.
 4424. Themixture of claim 4409, wherein greater than about 25% by weight of thecondensable hydrocarbons comprises oxygenated hydrocarbons.
 4425. Themixture of claim 4409, wherein the mixture comprises hydrocarbons havinggreater than about 2 carbon atoms, and wherein the weight ratio ofhydrocarbons having greater than about 2 carbon atoms to methane isgreater than about 0.3.
 4426. A mixture produced from a portion of anoil shale formation, comprising: condensable hydrocarbons, wherein lessthan about 5% by weight of the condensable hydrocarbons compriseshydrocarbons having a carbon number greater than about 25; wherein thecondensable hydrocarbons further comprise: oxygenated hydrocarbons,wherein greater than about 5% by weight of the condensable hydrocarbonscomprises oxygenated hydrocarbons; olefins, wherein less than about 10%by weight of the condensable hydrocarbons comprises olefins; andaromatic compounds, wherein greater than about 30% by weight of thecondensable hydrocarbons comprises aromatic compounds; andnon-condensable hydrocarbons comprising H₂, wherein greater than about15% by weight of the non-condensable hydrocarbons comprises H₂. 4427.The mixture of claim 4426, wherein the non-condensable hydrocarbonsfurther comprises hydrocarbons having carbon numbers of less than 5, andwherein a weight ratio of hydrocarbons having carbon numbers from 2through 4, to methane, is greater than approximately
 1. 4428. Themixture of claim 4426, wherein the non-condensable hydrocarbons compriseethene and ethane, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.4429. The mixture of claim 4426, wherein the condensable hydrocarbonsfurther comprise nitrogen containing compounds, and wherein less thanabout 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 4430. The mixture of claim 4426,wherein the condensable hydrocarbons further comprise oxygen containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is oxygen.
 4431. Themixture of claim 4426, wherein the condensable hydrocarbons furthercomprise sulfur containing compounds, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 4432. The mixture of claim 4426, wherein thecondensable hydrocarbons further comprise oxygen containing compounds,wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 4433. The mixture of claim4426, wherein the condensable hydrocarbons further comprise multi-ringaromatics, and wherein less than about 5% by weight of the condensablehydrocarbons comprises multi-ring aromatics with more than two rings.4434. The mixture of claim 4426, wherein the condensable hydrocarbonsfurther comprise asphaltenes, and wherein less than about 0.3% by weightof the condensable hydrocarbons are asphaltenes.
 4435. The mixture ofclaim 4426, wherein the condensable hydrocarbons comprise cycloalkanes,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 4436. The mixture of claim 4426, whereingreater than about 10% by volume and less than about 80% by volume ofthe non-condensable hydrocarbons comprises hydrogen.
 4437. The mixtureof claim 4426, further comprising ammonia, and wherein greater thanabout 0.05% by weight of the produced mixture is ammonia.
 4438. Themixture of claim 4426, further comprising ammonia, and wherein theammonia is used to produce fertilizer.
 4439. The mixture of claim 4426,wherein about 0.1% to about 5% by weight of the condensable hydrocarbonscomprises olefins.
 4440. The mixture of claim 4426, wherein about 0.1%to about 2% by weight of the condensable hydrocarbons comprises olefins.4441. The mixture of claim 4426, wherein the condensable hydrocarbonscomprises oxygenated hydrocarbons, and wherein greater than about 15% byweight of the condensable hydrocarbons comprises oxygenatedhydrocarbons.
 4442. The mixture of claim 4426, wherein the mixturecomprises hydrocarbons having greater than about 2 carbon atoms, andwherein the weight ratio of hydrocarbons having greater than about 2carbon atoms to methane is greater than about 0.3.
 4443. Condensablehydrocarbons produced from a portion of an oil shale formation,comprising: olefins, wherein about 0.1% by weight to about 15% by weightof the condensable hydrocarbons comprises olefins; oxygenatedhydrocarbons, wherein less than about 15% by weight of the condensablehydrocarbons comprises oxygenated hydrocarbons; and asphaltenes, whereinless than about 0.1% by weight of the condensable hydrocarbons comprisesasphaltenes.
 4444. The mixture of claim 4443, wherein the condensablehydrocarbons further comprises hydrocarbons having a carbon number ofgreater than approximately 25, and wherein less than about 15 weight %of the hydrocarbons in the mixture have a carbon number greater thanapproximately
 25. 4445. The mixture of claim 4443, wherein about 0.1% byweight to about 5% by weight of the condensable hydrocarbons comprisesolefins.
 4446. The mixture of claim 4443, wherein the condensablehydrocarbons further comprises non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise ethene and ethane, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 4447. The mixture of claim 4443,wherein the condensable hydrocarbons further comprises nitrogencontaining compounds, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 4448. The mixture of claim 4443, wherein the condensablehydrocarbons further comprises oxygen containing compounds, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 4449. The mixture of claim 4443,wherein the condensable hydrocarbons further comprises sulfur containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is sulfur.
 4450. Themixture of claim 4443, wherein the condensable hydrocarbons furthercomprises oxygen containing compounds, wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons comprise oxygencontaining compounds, and wherein the oxygen containing compoundscomprise phenols.
 4451. The mixture of claim 4443, wherein thecondensable hydrocarbons further comprises aromatic compounds, andwherein greater than about 20% by weight of the condensable hydrocarbonsare aromatic compounds.
 4452. The mixture of claim 4443, wherein thecondensable hydrocarbons further comprises multi-ring aromatics, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 4453. Themixture of claim 4443, wherein the condensable hydrocarbons furthercomprises cycloalkanes, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 4454. Themixture of claim 4443, wherein the condensable hydrocarbons comprisesnon-condensable hydrocarbons, and wherein the non-condensablehydrocarbons comprise hydrogen, and wherein greater than about 10% byvolume of the non-condensable hydrocarbons and less than about 80% byvolume of the non-condensable hydrocarbons comprises hydrogen.
 4455. Themixture of claim 4443, further comprising ammonia, and wherein greaterthan about 0.05% by weight of the produced mixture is ammonia.
 4456. Themixture of claim 4443, further comprising ammonia, and wherein theammonia is used to produce fertilizer.
 4457. The mixture of claim 4443,wherein about 0.1% by weight to about 2% by weight of the condensablehydrocarbons comprises olefins.
 4458. A mixture of condensablehydrocarbons produced from a portion of an oil shale formation,comprising: olefins, wherein about 0.1% by weight to about 2% by weightof the condensable hydrocarbons comprises olefins; multi-ring aromatics,wherein less than about 2% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings; and oxygenatedhydrocarbons, wherein greater than about 25% by weight of thecondensable hydrocarbons comprises oxygenated hydrocarbons.
 4459. Themixture of claim 4458, further comprising hydrocarbons having a carbonnumber of greater than approximately 25, wherein less than about 5weight % of the hydrocarbons in the mixture have a carbon number greaterthan approximately
 25. 4460. The mixture of claim 4458, wherein thecondensable hydrocarbons further comprises nitrogen containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is nitrogen.
 4461. Themixture of claim 4458, wherein the condensable hydrocarbons furthercomprises oxygen containing compounds, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 4462. The mixture of claim 4458, wherein thecondensable hydrocarbons further comprises sulfur containing compounds,and wherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 4463. The mixture ofclaim 4458, wherein the condensable hydrocarbons further comprisesoxygen containing compounds, wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.4464. The mixture of claim 4458, wherein the condensable hydrocarbonsfurther comprises aromatic compounds, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 4465.The mixture of claim 4458, wherein the condensable hydrocarbons furthercomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 4466. Themixture of claim 4458, wherein the condensable hydrocarbons furthercomprises cycloalkanes, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 4467. Themixture of claim 4458, further comprising ammonia, wherein greater thanabout 0.05% by weight of the produced mixture is ammonia.
 4468. Themixture of claim 4458, further comprising ammonia, wherein the ammoniais used to produce fertilizer.
 4469. A mixture produced from a portionof an oil shale formation, comprising: non-condensable hydrocarbons andH₂, wherein greater than about 10% by volume of the non-condensablehydrocarbons and H₂ comprises H₂; ammonia and water, wherein greaterthan about 0.5% by weight of the mixture comprises ammonia; andcondensable hydrocarbons.
 4470. The mixture of claim 4469, wherein thenon-condensable hydrocarbons further comprise hydrocarbons having carbonnumbers of less than 5, and wherein a weight ratio of the hydrocarbonshaving carbon numbers from 2 through 4 to methane, in the mixture isgreater than approximately
 1. 4471. The mixture of claim 4469, whereingreater than about 0.1% by weight of the condensable hydrocarbons areolefins, and wherein less than about 15% by weight of the condensablehydrocarbons are olefins.
 4472. The mixture of claim 4469, wherein thenon-condensable hydrocarbons further comprise ethene and ethane, whereina molar ratio of ethene to ethane in the non-condensable hydrocarbons isgreater than about 0.001, and wherein a molar ratio of ethene to ethanein the non-condensable hydrocarbons is less than about 0.15.
 4473. Themixture of claim 4469, wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 4474. The mixture of claim 4469, wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 4475. The mixture of claim 4469, wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 4476. The mixture of claim 4469,wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 4477. The mixture of claim4469, wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 4478. The mixture of claim 4469,wherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 4479. Themixture of claim 4469, wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 4480. The mixture of claim4469, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons are cycloalkanes.
 4481. The mixture of claim4469, wherein the H₂ is less than about 80% by volume of thenon-condensable hydrocarbons and H₂.
 4482. The mixture of claim 4469,wherein the condensable hydrocarbons further comprise sulfur containingcompounds.
 4483. The mixture of claim 4469, wherein the ammonia is usedto produce fertilizer.
 4484. The mixture of claim 4469, wherein lessthan about 5% of the condensable hydrocarbons have carbon numbersgreater than
 25. 4485. The mixture of claim 4469, wherein thecondensable hydrocarbons comprise olefins, wherein greater than about0.001% by weight of the condensable hydrocarbons comprise olefins, andwherein less than about 15% by weight of the condensable hydrocarbonscomprise olefins.
 4486. The mixture of claim 4469, wherein thecondensable hydrocarbons comprise olefins, wherein greater than about0.001% by weight of the condensable hydrocarbons comprise olefins, andwherein less than about 10% by weight of the condensable hydrocarbonscomprise olefins.
 4487. The mixture of claim 4469, wherein thecondensable hydrocarbons comprise oxygenated hydrocarbons, and whereingreater than about 1.5% by weight of the condensable hydrocarbonscomprises oxygenated hydrocarbons.
 4488. The mixture of claim 4469,wherein the condensable hydrocarbons further comprise nitrogencontaining compounds.
 4489. A method of treating an oil shale formationin situ comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 4490.The method of claim 4489, wherein three or more of the heat sources arelocated in the formation in a plurality of the units, and wherein theplurality of units are repeated over an area of the formation to form arepetitive pattern of units.
 4491. The method of claim 4489, whereinthree or more of the heat sources are located in the formation in aplurality of the units, wherein the plurality of units are repeated overan area of the formation to form a repetitive pattern of units, andwherein a ratio of heat sources in the repetitive pattern of units toproduction wells in the repetitive pattern is greater than approximately5.
 4492. The method of claim 4489, wherein three or more of the heatsources are located in the formation in a plurality of the units,wherein the plurality of units are repeated over an area of theformation to form a repetitive pattern of units, wherein three or moreproduction wells are located within an area defined by the plurality ofunits, wherein the three or more production wells are located in theformation in a unit of production wells, and wherein the unit ofproduction wells comprises a triangular pattern.
 4493. The method ofclaim 4489, wherein three or more of the heat sources are located in theformation in a plurality of the units, wherein the plurality of unitsare repeated over an area of the formation to form a repetitive patternof units, wherein three or more injection wells are located within anarea defined by the plurality of units, wherein the three or moreinjection wells are located in the formation in a unit of injectionwells, and wherein the unit of injection wells comprises a triangularpattern.
 4494. The method of claim 4489, wherein three or more of theheat sources are located in the formation in a plurality of the units,wherein the plurality of units are repeated over an area of theformation to form a repetitive pattern of units, wherein three or moreproduction wells and three or more injection wells are located within anarea defined by the plurality of units, wherein the three or moreproduction wells are located in the formation in a unit of productionwells, wherein the unit of production wells comprises a first triangularpattern, wherein the three or more injection wells are located in theformation in a unit of injection wells, wherein the unit of injectionwells comprises a second triangular pattern, and wherein the firsttriangular pattern is substantially different than the second triangularpattern.
 4495. The method of claim 4489, wherein three or more of theheat sources are located in the formation in a plurality of the units,wherein the plurality of units are repeated over an area of theformation to form a repetitive pattern of units, wherein three or moremonitoring wells are located within an area defined by the plurality ofunits, wherein the three or more monitoring wells are located in theformation in a unit of monitoring wells, and wherein the unit ofmonitoring wells comprises a triangular pattern.
 4496. The method ofclaim 4489, wherein a production well is located in an area defined bythe unit of heat sources.
 4497. The method of claim 4489, wherein threeor more of the heat sources are located in the formation in a first unitand a second unit, wherein the first unit is adjacent to the secondunit, and wherein the first unit is inverted with respect to the secondunit.
 4498. The method of claim 4489, wherein a distance between each ofthe heat sources in the unit of heat sources varies by less than about20%.
 4499. The method of claim 4489, wherein a distance between each ofthe heat sources in the unit of heat sources is approximately equal.4500. The method of claim 4489, wherein providing heat from three ormore heat sources comprises substantially uniformly providing heat to atleast the portion of the formation.
 4501. The method of claim 4489,wherein the heated portion comprises a substantially uniform temperaturedistribution.
 4502. The method of claim 4489, wherein the heated portioncomprises a substantially uniform temperature distribution, and whereina difference between a highest temperature in the heated portion and alowest temperature in the heated portion comprises less than about 200°C.
 4503. The method of claim 4489, wherein a temperature at an outerlateral boundary of the triangular pattern and a temperature at a centerof the triangular pattern are approximately equal.
 4504. The method ofclaim 4489, wherein a temperature at an outer lateral boundary of thetriangular pattern and a temperature at a center of the triangularpattern increase substantially linearly after an initial period of time,and wherein the initial period of time comprises less than approximately3 months.
 4505. The method of claim 4489, wherein a time required toincrease an average temperature of the heated portion to a selectedtemperature with the triangular pattern of heat sources is substantiallyless than a time required to increase the average temperature of theheated portion to the selected temperature with a hexagonal pattern ofheat sources, and wherein a space between each of the heat sources inthe triangular pattern is approximately equal to a space between each ofthe heat sources in the hexagonal pattern.
 4506. The method of claim4489, wherein a time required to increase a temperature at a coldestpoint within the heated portion to a selected temperature with thetriangular pattern of heat sources is substantially less than a timerequired to increase a temperature at the coldest point within theheated portion to the selected temperature with a hexagonal pattern ofheat sources, and wherein a space between each of the heat sources inthe triangular pattern is approximately equal to a space between each ofthe heat sources in the hexagonal pattern.
 4507. The method of claim4489, wherein a time required to increase a temperature at a coldestpoint within the heated portion to a selected temperature with thetriangular pattern of heat sources is substantially less than a timerequired to increase a temperature at the coldest point within theheated portion to the selected temperature with a hexagonal pattern ofheat sources, and wherein a number of heat sources per unit area in thetriangular pattern is equal to the number of heat sources per unit arein the hexagonal pattern of heat sources.
 4508. The method of claim4489, wherein a time required to increase a temperature at a coldestpoint within the heated portion to a selected temperature with thetriangular pattern of heat sources is substantially equal to a timerequired to increase a temperature at the coldest point within theheated portion to the selected temperature with a hexagonal pattern ofheat sources, and wherein a space between each of the heat sources inthe triangular pattern is approximately 5 m greater than a space betweeneach of the heat sources in the hexagonal pattern.
 4509. The method ofclaim 4489, wherein providing heat from three or more heat sources to atleast the portion of formation comprises: heating a selected volume (V)of the oil shale formation from three or more of the heat sources,wherein the formation has an average heat capacity (C_(v)), and whereinheat from three or more of the heat sources pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 4510. The method of claim 4489, whereinthree or more of the heat sources comprise electrical heaters.
 4511. Themethod of claim 4489, wherein three or more of the heat sources comprisesurface burners.
 4512. The method of claim 4489, wherein three or moreof the heat sources comprise flameless distributed combustors.
 4513. Themethod of claim 4489, wherein three or more of the heat sources comprisenatural distributed combustors.
 4514. The method of claim 4489, furthercomprising: allowing the heat to transfer from three or more of the heatsources to a selected section of the formation such that heat from threeor more of the heat sources pyrolyzes at least some hydrocarbons withinthe selected section of the formation; and producing a mixture of fluidsfrom the formation.
 4515. The method of claim 4514, further comprisingcontrolling a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 4516. The method of claim 4514, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1.0° C. per day during pyrolysis.
 4517. Themethod of claim 4514, wherein allowing the heat to transfer from threeor more of the heat sources to the selected section comprisestransferring heat substantially by conduction.
 4518. The method of claim4514, wherein providing heat from three or more of the heat sources toat least the portion of the formation comprises heating the selectedsection such that a thermal conductivity of at least a portion of theselected section is greater than about 0.5 W/m ° C.
 4519. The method ofclaim 4514, wherein the produced mixture comprises an API gravity of atleast 25°.
 4520. The method of claim 4514, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 4521.The method of claim 4514, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 4522. The method of claim 4514, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 4523. The method of claim 4514, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 4524. The method of claim 4514,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 4525. The method ofclaim 4514, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 4526. Themethod of claim 4514, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 4527. The method ofclaim 4514, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 4528. The method of claim 4514, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.1% byweight of the condensable hydrocarbons are asphaltenes.
 4529. The methodof claim 4514, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 4530. The method of claim4514, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein greater than about 10% by volume of the non-condensablecomponent comprises hydrogen, and wherein the hydrogen is less thanabout 80% by volume of the non-condensable component.
 4531. The methodof claim 4514, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 4532. The method of claim 4514, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 4533. The method of claim 4514, further comprisingcontrolling formation conditions to produce a mixture of hydrocarbonfluids and H₂, wherein a partial pressure of H₂ within the mixture isgreater than about 2.0 bars absolute.
 4534. The method of claim 4514,further comprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 4535. The method of claim 4514, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 4536. The method ofclaim 4514, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 4537. The method ofclaim 4514, further comprising: producing hydrogen from the formation;and hydrogenating a portion of the produced condensable hydrocarbonswith at least a portion of the produced hydrogen.
 4538. The method ofclaim 4514, wherein allowing the heat to transfer from three or more ofthe heat sources to the selected section of the formation comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 4539. The method of claim 4514,wherein allowing the heat to transfer from three or more of the heatsources to the selected section of the formation comprises substantiallyuniformly increasing a permeability of a majority of the selectedsection.
 4540. The method of claim 4514, further comprising controllingthe heat from three or more heat sources to yield greater than about 60%by weight of condensable hydrocarbons, as measured by Fischer Assay.4541. The method of claim 4514, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well.4542. The method of claim 4541, wherein at least about 20 heat sourcesare disposed in the formation for each production well.
 4543. The methodof claim 4514, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,and wherein the unit of heat sources comprises a triangular pattern.4544. The method of claim 4514, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, wherein the unit of heat sources comprises atriangular pattern, and wherein a plurality of the units are repeatedover an area of the formation to form a repetitive pattern of units.4545. A method for in situ production of synthesis gas from an oil shaleformation, comprising: heating a section of the formation to atemperature sufficient to allow synthesis gas generation, wherein apermeability of the section is substantially uniform and greater than apermeability of an unheated section of the formation when thetemperature sufficient to allow synthesis gas generation within theformation is achieved; providing a synthesis gas generating fluid to thesection to generate synthesis gas; and removing synthesis gas from theformation.
 4546. The method of claim 4545, wherein the permeability ofthe section is greater than about 100 millidarcy when the temperaturesufficient to allow synthesis gas generation within the formation isachieved.
 4547. The method of claim 4545, wherein the temperaturesufficient to allow synthesis gas generation ranges from approximately400° C. to approximately 1200° C.
 4548. The method of claim 4545,further comprising heating the section when providing the synthesis gasgenerating fluid to inhibit temperature decrease in the section due tosynthesis gas generation.
 4549. The method of claim 4545, whereinheating the section comprises convecting an oxidizing fluid into aportion of the section, wherein the temperature within the section is isabove a temperature sufficient to support oxidation of carbon within thesection with the oxidizing fluid, and reacting the oxidizing fluid withcarbon in the section to generate heat within the section.
 4550. Themethod of claim 4549, wherein the oxidizing fluid comprises air. 4551.The method of claim 4550, wherein an amount of the oxidizing fluidconvected into the section is configured to inhibit formation of oxidesof nitrogen by maintaining a reaction temperature below a temperaturesufficient to produce oxides of nitrogen compounds.
 4552. The method ofclaim 4545, wherein heating the section comprises diffusing an oxidizingfluid to reaction zones adjacent to wellbores within the formation,oxidizing carbon within the reaction zone to generate heat, andtransferring the heat to the section.
 4553. The method of claim 4545,wherein heating the section comprises heating the section by transfer ofheat from one or more of electrical heaters.
 4554. The method of claim4545, wherein heating the section to a temperature sufficient to allowsynthesis gas generation and providing a synthesis gas generating fluidto the section comprises introducing steam into the section to heat theformation and to generate synthesis gas.
 4555. The method of claim 4545,further comprising controlling the heating of the section and provisionof the synthesis gas generating fluid to maintain a temperature withinthe section above the temperature sufficient to generate synthesis gas.4556. The method of claim 4545, further comprising: monitoring acomposition of the produced synthesis gas; and controlling heating ofthe section and provision of the synthesis gas generating fluid tomaintain the composition of the produced synthesis gas within a selectedrange.
 4557. The method of claim 4556, wherein the selected rangecomprises a ratio of H₂ to CO of about 2:1.
 4558. The method of claim4545, wherein the synthesis gas generating fluid comprises liquid water.4559. The method of claim 4545, wherein the synthesis gas generatingfluid comprises steam.
 4560. The method of claim 4545, wherein thesynthesis gas generating fluid comprises water and carbon dioxide, andwherein the carbon dioxide inhibits production of carbon dioxide fromhydrocarbon containing material within the section.
 4561. The method ofclaim 4560, wherein a portion of the carbon dioxide within the synthesisgas generating fluid comprises carbon dioxide removed from theformation.
 4562. The method of claim 4545, wherein the synthesis gasgenerating fluid comprises carbon dioxide, and wherein a portion of thecarbon dioxide reacts with carbon in the formation to generate carbonmonoxide.
 4563. The method of claim 4562, wherein a portion of thecarbon dioxide within the synthesis gas generating fluid comprisescarbon dioxide removed from the formation.
 4564. The method of claim4545, wherein providing the synthesis gas generating fluid to thesection comprises raising a water table of the formation to allow waterto flow into the section.
 4565. The method of claim 4545, wherein thesynthesis gas is removed from a producer well equipped with a heatingsource, and wherein a portion of the heating source adjacent to asynthesis gas producing zone operates at a substantially constanttemperature to promote production of the synthesis gas wherein thesynthesis gas has a selected composition.
 4566. The method of claim4565, wherein the substantially constant temperature is about 700° C.,and wherein the selected composition has a H₂ to CO ratio of about 2:1.4567. The method of claim 4545, wherein the synthesis gas generatingfluid comprises water and hydrocarbons having carbon numbers less than5, and wherein at least a portion of the hydrocarbons are subjected to areaction within the section to increase a H₂ concentration of thegenerated synthesis gas.
 4568. The method of claim 4545, wherein thesynthesis gas generating fluid comprises water and hydrocarbons havingcarbon numbers greater than 4, and wherein at least a portion of thehydrocarbons react within the section to increase an energy content ofthe synthesis gas removed from the formation.
 4569. The method of claim4545, further comprising maintaining a pressure within the formationduring synthesis gas generation, and passing produced synthesis gasthrough a turbine to generate electricity.
 4570. The method of claim4545, further comprising generating electricity from the synthesis gasusing a fuel cell.
 4571. The method of claim 4545, further comprisinggenerating electricity from the synthesis gas using a fuel cell,separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent sectionof the formation.
 4572. The method of claim 4545, further comprisingusing a portion of the synthesis gas as a combustion fuel to heat theformation.
 4573. The method of claim 4545, further comprising convertingat least a portion of the produced synthesis gas to condensablehydrocarbons using a Fischer-Tropsch synthesis process.
 4574. The methodof claim 4545, further comprising converting at least a portion of theproduced synthesis gas to methanol.
 4575. The method of claim 4545,further comprising converting at least a portion of the producedsynthesis gas to gasoline.
 4576. The method of claim 4545, furthercomprising converting at least a portion of the synthesis gas to methaneusing a catalytic methanation process.
 4577. The method of claim 4545,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 4578.The method of claim 4545, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 4579. A methodof treating an oil shale formation in situ, comprising: providing heatfrom one or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources tosubstantially uniformly increase a permeability of the portion and toincrease a temperature of the portion to a temperature sufficient toallow synthesis gas generation; providing a synthesis gas generatingfluid to at least the portion of the selected section, wherein thesynthesis gas generating fluid comprises carbon dioxide; obtaining aportion of the carbon dioxide of the synthesis gas generating fluid fromthe formation; and producing synthesis gas from the formation.
 4580. Themethod of claim 4579, wherein the temperature sufficient to allowsynthesis gas generation is within a range from about 400° C. to about1200° C.
 4581. The method of claim 4579, further comprising using asecond portion of the separated carbon dioxide as a flooding agent toproduce hydrocarbon bed methane from an oil shale formation.
 4582. Themethod of claim 4581, wherein the oil shale formation is a deep oilshale formation over 760 m below ground surface.
 4583. The method ofclaim 4581, wherein the oil shale formation adsorbs some of the carbondioxide to sequester the carbon dioxide.
 4584. The method of claim 4579,further comprising using a second portion of the separated carbondioxide as a flooding agent for enhanced oil recovery.
 4585. The methodof claim 4579, wherein the synthesis gas generating fluid compriseswater and hydrocarbons having carbon numbers less than 5, and wherein atleast a portion of the hydrocarbons undergo a reaction within theselected section to increase a H₂ concentration within the producedsynthesis gas.
 4586. The method of claim 4579, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersgreater than 4, and wherein at least a portion of the hydrocarbons reactwithin the selected section to increase an energy content of theproduced synthesis gas.
 4587. The method of claim 4579, furthercomprising maintaining a pressure within the formation during synthesisgas generation, and passing produced synthesis gas through a turbine togenerate electricity.
 4588. The method of claim 4579, further comprisinggenerating electricity from the synthesis gas using a fuel cell. 4589.The method of claim 4579, further comprising generating electricity fromthe synthesis gas using a fuel cell, separating carbon dioxide from afluid exiting the fuel cell, and storing a portion of the separatedcarbon dioxide within a spent portion of the formation.
 4590. The methodof claim 4579, further comprising using a portion of the synthesis gasas a combustion fuel for heating the formation.
 4591. The method ofclaim 4579, further comprising converting at least a portion of theproduced synthesis gas to condensable hydrocarbons using aFischer-Tropsch synthesis process.
 4592. The method of claim 4579,further comprising converting at least a portion of the producedsynthesis gas to methanol.
 4593. The method of claim 4579, furthercomprising converting at least a portion of the produced synthesis gasto gasoline.
 4594. The method of claim 4579, further comprisingconverting at least a portion of the synthesis gas to methane using acatalytic methanation process.
 4595. The method of claim 4579, wherein atemperature of at least one heat source is maintained at a temperatureof less than approximately 700° C. to produce a synthesis gas having aratio of H₂ to carbon monoxide of greater than about
 2. 4596. The methodof claim 4579, wherein a temperature of at least one heat source ismaintained at a temperature of greater than approximately 700° C. toproduce a synthesis gas having a ratio of H₂ to carbon monoxide of lessthan about
 2. 4597. The method of claim 4579, wherein a temperature ofat least one heat source is maintained at a temperature of approximately700° C. to produce a synthesis gas having a ratio of H₂ to carbonmonoxide of approximately
 2. 4598. The method of claim 4579, wherein aheat source of the one or more of heat sources comprises an electricalheater.
 4599. The method of claim 4579, wherein a heat source of the oneor more heat sources comprises a natural distributed heater.
 4600. Themethod of claim 4579, wherein a heat source of the one or more heatsources comprises a flameless distributed combustor (FDC) heater, andwherein fluids are produced from the wellbore of the FDC heater througha conduit positioned within the wellbore.
 4601. The method of claim4579, further comprising providing heat from three or more heat sourcesto at least a portion of the formation, wherein three or more of theheat sources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 4602.The method of claim 4579, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 4603. A methodof in situ synthesis gas production, comprising: providing heat from oneor more flameless distributed combustor heaters to at least a firstportion of an oil shale formation; allowing the heat to transfer fromthe one or more heaters to a selected section of the formation such thatthe heat from the one or more heaters substantially uniformly increasesa permeability of the selected section, and to raise a temperature ofthe selected section to a temperature sufficient to generate synthesisgas; introducing a synthesis gas producing fluid into the selectedsection to generate synthesis gas; and removing synthesis gas from theformation.
 4604. The method of claim 4603, wherein the one or moreheaters comprise at least two heaters, and wherein superposition of heatfrom at least the two heaters substantially uniformly increases apermeability of the selected section, and raises a temperature of theselected section to a temperature sufficient to generate synthesis gas.4605. The method of claim 4603, further comprising producing thesynthesis gas from the formation under pressure, and generatingelectricity from the produced synthesis gas by passing the producedsynthesis gas through a turbine.
 4606. The method of claim 4603, furthercomprising producing pyrolyzation products from the formation whenraising the temperature of the selected section to the temperaturesufficient to generate synthesis gas.
 4607. The method of claim 4603,further comprising separating a portion of carbon dioxide from theremoved synthesis gas, and storing the carbon dioxide within a spentportion of the formation.
 4608. The method of claim 4603, furthercomprising storing carbon dioxide within a spent portion of theformation, wherein an amount of carbon dioxide stored within the spentportion of the formation is equal to or greater than an amount of carbondioxide within the removed synthesis gas.
 4609. The method of claim4603, further comprising separating a portion of H₂ from the removedsynthesis gas; and using a portion of the separated H₂ as fuel for theone or more heaters.
 4610. The method of claim 4603, further comprisingusing a portion of exhaust products from one or more heaters as aportion of the synthesis gas producing fluid
 4611. The method of claim4603, further comprising using a portion of the removed synthesis gaswith a fuel cell to generate electricity.
 4612. The method of claim4611, wherein the fuel cell produces steam, and wherein a portion of thesteam is used as a portion of the synthesis gas producing fluid. 4613.The method of claim 4611, wherein the fuel cell produces carbon dioxide,and wherein a portion of the carbon dioxide is introduced into theformation to react with carbon within the formation to produce carbonmonoxide.
 4614. The method of claim 4611, wherein the fuel cell producescarbon dioxide, and further comprising storing an amount of carbondioxide within a spent portion of the formation equal or greater to anamount of the carbon dioxide produced by the fuel cell.
 4615. The methodof claim 4603, further comprising using a portion of the removedsynthesis gas as a feed product for formation of hydrocarbons.
 4616. Themethod of claim 4603, wherein the synthesis gas producing fluidcomprises hydrocarbons having carbon numbers less than 5, and whereinthe hydrocarbons crack within the formation to increase an amount of H₂within the generated synthesis gas.
 4617. The method of claim 4603,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 4618.The method of claim 4603, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 4619. A methodof treating an oil shale formation, comprising: heating a portion of theformation with one or more electrical heaters to a temperaturesufficient to pyrolyze hydrocarbons within the portion; producingpyrolyzation fluid from the formation; separating a fuel cell feedstream from the pyrolyzation fluid; and directing the fuel cell feedstream to a fuel cell to produce electricity.
 4620. The method of claim4619, wherein the fuel cell is a molten carbonate fuel cell.
 4621. Themethod of claim 4619, wherein the fuel cell is a solid oxide fuel cell.4622. The method of claim 4619, further comprising using a portion ofthe produced electricity to power the electrical heaters.
 4623. Themethod of claim 4619, wherein heating the portion of the formation isperformed at a rate sufficient to increase a permeability of the portionand to produce a substantially uniform permeability within the portion.4624. The method of claim 4619, wherein the fuel cell feed streamcomprises H₂ and hydrocarbons having a carbon number of less than 5.4625. The method of claim 4619, wherein the fuel cell feed streamcomprises H₂ and hydrocarbons having a carbon number of less than 3.4626. The method of claim 4619, further comprising hydrogenating thepyrolyzation fluid with a portion of H₂ from the pyrolyzation fluid.4627. The method of claim 4619, wherein the hydrogenation is done insitu by directing the H₂ into the formation.
 4628. The method of claim4619, wherein the hydrogenation is done in a surface unit.
 4629. Themethod of claim 4619, further comprising directing hydrocarbon fluidhaving carbon numbers less than 5 adjacent to at least one of theelectrical heaters, cracking a portion of the hydrocarbon s to produceH₂, and producing a portion of the hydrogen from the formation. 4630.The method of claim 4629, further comprising directing an oxidizingfluid adjacent to at least the one of the electrical heaters, oxidizingcoke deposited on or near the at least one of the electrical heaterswith the oxidizing fluid.
 4631. The method of claim 4619, furthercomprising storing CO₂ generated in the fuel cell within the formation.4632. The method of claim 4631, wherein the CO₂ is adsorbed to carbonmaterial within a spent portion of the formation.
 4633. The method ofclaim 4619, further comprising cooling the portion to form a spentportion of formation.
 4634. The method of claim 4633, wherein coolingthe portion comprises introducing water into the portion to producesteam, and removing steam from the formation.
 4635. The method of claim4634, further comprising using a portion of the removed steam to heat asecond portion of the formation.
 4636. The method of claim 4634, furthercomprising using a portion of the removed steam as a synthesis gasproducing fluid in a second portion of the formation.
 4637. The methodof claim 4619, further comprising: heating the portion to a temperaturesufficient to support generation of synthesis gas after production ofthe pyrolyzation fluids; introducing a synthesis gas producing fluidinto the portion to generate synthesis gas; and removing a portion ofthe synthesis gas from the formation.
 4638. The method of claim 4637,further comprising producing the synthesis gas from the formation underpressure, and generating electricity from the produced synthesis gas bypassing the produced synthesis gas through a turbine.
 4639. The methodof claim 4637, further comprising using a first portion of the removedsynthesis gas as fuel cell feed.
 4640. The method of claim 4637, furthercomprising producing steam from operation of the fuel cell, and usingthe steam as part of the synthesis gas producing fluid.
 4641. The methodof claim 4637, further comprising using carbon dioxide from the fuelcell as a part of the synthesis gas producing fluid.
 4642. The method ofclaim 4637, further comprising using a portion of the synthesis gas toproduce hydrocarbon product.
 4643. The method of claim 4637, furthercomprising cooling the portion to form a spent portion of formation.4644. The method of claim 4643, wherein cooling the portion comprisesintroducing water into the portion to produce steam, and removing steamfrom the formation.
 4645. The method of claim 4644, further comprisingusing a portion of the removed steam to heat a second portion of theformation.
 4646. The method of claim 4644, further comprising using aportion of the removed steam as a synthesis gas producing fluid in asecond portion of the formation.
 4647. The method of claim 4619, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, and wherein the unitof heat sources comprises a triangular pattern.
 4648. The method ofclaim 4619, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,wherein the unit of heat sources comprises a triangular pattern, andwherein a plurality of the units are repeated over an area of theformation to form a repetitive pattern of units.
 4649. A method for insitu production of synthesis gas from an oil shale formation,comprising: providing heat from one or more heat sources to at least aportion of the formation; allowing the heat to transfer from the one ormore heat sources to a selected section of the formation such that theheat from the one or more heat sources pyrolyzes at least some of thehydrocarbons within the selected section of the formation; producingpyrolysis products from the formation; heating at least a portion of theselected section to a temperature sufficient to generate synthesis gas;providing a synthesis gas generating fluid to at least the portion ofthe selected section to generate synthesis gas; and producing a portionof the synthesis gas from the formation.
 4650. The method of claim 4649,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 4651. The method of claim 4649, further comprising allowingthe heat to transfer from the one or more heat sources to the selectedsection to substantially uniformly increase a permeability of theselected section.
 4652. The method of claim 4649, further comprisingcontrolling heat transfer from the one or more heat sources to produce apermeability within the selected section of greater than about 100millidarcy.
 4653. The method of claim 4649, further comprising heatingat least the portion of the selected section when providing thesynthesis gas generating fluid to inhibit temperature decrease withinthe selected section during synthesis gas generation.
 4654. The methodof claim 4649, wherein the temperature sufficient to allow synthesis gasgeneration is within a range from approximately 400° C. to approximately1200° C.
 4655. The method of claim 4649, wherein heating at least theportion of the selected section to a temperature sufficient to allowsynthesis gas generation comprises: heating zones adjacent to wellboresof one or more heat sources with heaters disposed in the wellbores,wherein the heaters are configured to raise temperatures of the zones totemperatures sufficient to support reaction of hydrocarbon containingmaterial within the zones with an oxidizing fluid; introducing theoxidizing fluid to the zones substantially by diffusion; allowing theoxidizing fluid to react with at least a portion of the hydrocarboncontaining material within the zones to produce heat in the zones; andtransferring heat from the zones to the selected section.
 4656. Themethod of claim 4649, wherein heating at least the portion of theselected section to a temperature sufficient to allow synthesis gasgeneration comprises: introducing an oxidizing fluid into the formationthrough a wellbore; transporting the oxidizing fluid substantially byconvection into the portion of the selected section, wherein the portionof the selected section is at a temperature sufficient to support anoxidation reaction with the oxidizing fluid; and reacting the oxidizingfluid within the portion of the selected section to generate heat andraise the temperature of the portion.
 4657. The method of claim 4649,wherein the one or more heat sources comprise one or more electricalheaters disposed in the formation.
 4658. The method of claim 4649,wherein the one or more heat sources comprise one or more heater wells,wherein at least one heater well comprises a conduit disposed within theformation, and further comprising heating the conduit by flowing a hotfluid through the conduit.
 4659. The method of claim 4649, whereinheating at least the portion of the selected section to a temperaturesufficient to allow synthesis gas generation and providing a synthesisgas generating fluid to at least the portion of the selected sectioncomprises introducing steam into the portion.
 4660. The method of claim4649, further comprising controlling the heating of at least the portionof selected section and provision of the synthesis gas generating fluidto maintain a temperature within at least the portion of the selectedsection above the temperature sufficient to generate synthesis gas.4661. The method of claim 4649, further comprising: monitoring acomposition of the produced synthesis gas; and controlling heating of atleast the portion of selected section and provision of the synthesis gasgenerating fluid to maintain the composition of the produced synthesisgas within a desired range.
 4662. The method of claim 4649, wherein thesynthesis gas generating fluid comprises liquid water.
 4663. The methodof claim 4649, wherein the synthesis gas generating fluid comprisessteam.
 4664. The method of claim 4649, wherein the synthesis gasgenerating fluid comprises water and carbon dioxide, wherein the carbondioxide inhibits production of carbon dioxide from the selected section.4665. The method of claim 4664, wherein a portion of the carbon dioxidewithin the synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 4666. The method of claim 4649, wherein thesynthesis gas generating fluid comprises carbon dioxide, and wherein aportion of the carbon dioxide reacts with carbon in the formation togenerate carbon monoxide.
 4667. The method of claim 4666, wherein aportion of the carbon dioxide within the synthesis gas generating fluidcomprises carbon dioxide removed from the formation.
 4668. The method ofclaim 4649, wherein providing the synthesis gas generating fluid to atleast the portion of the selected section comprises raising a watertable of the formation to allow water to flow into the at least theportion of the selected section.
 4669. The method of claim 4649, whereinthe synthesis gas generating fluid comprises water and hydrocarbonshaving carbon numbers less than 5, and wherein at least a portion of thehydrocarbons are subjected to a reaction within at least the portion ofthe selected section to increase a H₂ concentration within the producedsynthesis gas.
 4670. The method of claim 4649, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersgreater than 4, and wherein at least a portion of the hydrocarbons reactwithin at least the portion of the selected section to increase anenergy content of the produced synthesis gas.
 4671. The method of claim4649, further comprising maintaining a pressure within the formationduring synthesis gas generation, and passing produced synthesis gasthrough a turbine to generate electricity.
 4672. The method of claim4649, further comprising generating electricity from the synthesis gasusing a fuel cell.
 4673. The method of claim 4649, further comprisinggenerating electricity from the synthesis gas using a fuel cell,separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent sectionof the formation.
 4674. The method of claim 4649, further comprisingusing a portion of the synthesis gas as a combustion fuel for the one ormore heat sources.
 4675. The method of claim 4649, further comprisingconverting at least a portion of the produced synthesis gas tocondensable hydrocarbons using a Fischer-Tropsch synthesis process.4676. The method of claim 4649, further comprising converting at least aportion of the produced synthesis gas to methanol.
 4677. The method ofclaim 4649, further comprising converting at least a portion of theproduced synthesis gas to gasoline.
 4678. The method of claim 4649,further comprising converting at least a portion of the synthesis gas tomethane using a catalytic methanation process.
 4679. The method of claim4649, further comprising providing heat from three or more heat sourcesto at least a portion of the formation, wherein three or more of theheat sources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 4680.The method of claim 4649, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 4681. A methodfor in situ production of synthesis gas from an oil shale formation,comprising: heating a first portion of the formation to pyrolyze somehydrocarbons within the first portion; allowing the heat to transferfrom one or more heat sources to a selected section of the formation,pyrolyzing hydrocarbons within the selected section; producing fluidfrom the first portion, wherein the fluid comprises an aqueous fluid anda hydrocarbon fluid; heating a second portion of the formation to atemperature sufficient to allow synthesis gas generation; introducing atleast a portion of the aqueous fluid to the second section after thesection reaches the temperature sufficient to allow synthesis gasgeneration; and producing synthesis gas from the formation.
 4682. Themethod of claim 4681, wherein the temperature sufficient to allowsynthesis gas generation ranges from approximately 400° C. toapproximately 1200° C.
 4683. The method of claim 4681, furthercomprising separating ammonia within the aqueous phase from the aqueousphase prior to introduction of at least the portion of the aqueous fluidto the second section.
 4684. The method of claim 4681, wherein apermeability of the second portion of the formation is substantiallyuniform and greater than about 100 millidarcy when the temperaturesufficient to allow synthesis gas generation is achieved.
 4685. Themethod of claim 4681, further comprising heating the second portion ofthe formation during introduction of at least the portion of the aqueousfluid to the second section to inhibit temperature decrease in thesecond section due to synthesis gas generation.
 4686. The method ofclaim 4681, wherein heating the second portion of the formationcomprises convecting an oxidizing fluid into a portion of the secondportion that is above a temperature sufficient to support oxidation ofcarbon within the portion with the oxidizing fluid, and reacting theoxidizing fluid with carbon in the portion to generate heat within theportion.
 4687. The method of claim 4681, wherein heating the secondportion of the formation comprises diffusing an oxidizing fluid toreaction zones adjacent to wellbores within the formation, oxidizingcarbon within the reaction zones to generate heat, and transferring theheat to the second portion.
 4688. The method of claim 4681, whereinheating the second portion of the formation comprises heating the secondsection by transfer of heat from one or more electrical heaters. 4689.The method of claim 4681, wherein heating the second portion of theformation comprises heating the second section with a flamelessdistributed combustor.
 4690. The method of claim 4681, wherein heatingthe second portion of the formation comprises injecting steam into atleast the portion of the formation.
 4691. The method of claim 4681,wherein at least the portion of the aqueous fluid comprises a liquidphase.
 4692. The method of claim 4681, wherein the aqueous fluidcomprises a vapor phase.
 4693. The method of claim 4681, furthercomprising adding carbon dioxide to at least the portion of aqueousfluid to inhibit production of carbon dioxide from carbon within theformation.
 4694. The method of claim 4693, wherein a portion of thecarbon dioxide comprises carbon dioxide removed from the formation.4695. The method of claim 4681, further comprising adding hydrocarbonswith carbon numbers less than 5 to at least the portion of the aqueousfluid to increase a H₂ concentration within the produced synthesis gas.4696. The method of claim 4681, further comprising adding hydrocarbonswith carbon numbers less than 5 to at least the portion of the aqueousfluid to increase a H₂ concentration within the produced synthesis gas,wherein the hydrocarbons are obtained from the produced fluid.
 4697. Themethod of claim 4681, further comprising adding hydrocarbons with carbonnumbers greater than 4 to at least the portion of the aqueous fluid toincrease energy content of the produced synthesis gas.
 4698. The methodof claim 4681, further comprising adding hydrocarbons with carbonnumbers greater than 4 to at least the portion of the aqueous fluid toincrease energy content of the produced synthesis gas, wherein thehydrocarbons are obtained from the produced fluid.
 4699. The method ofclaim 4681, further comprising maintaining a pressure within theformation during synthesis gas generation, and passing producedsynthesis gas through a turbine to generate electricity.
 4700. Themethod of claim 4681, further comprising generating electricity from thesynthesis gas using a fuel cell.
 4701. The method of claim 4681, furthercomprising generating electricity from the synthesis gas using a fuelcell, separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent portionof the formation.
 4702. The method of claim 4681, further comprisingusing a portion of the synthesis gas as a combustion fuel for the one ormore heat sources.
 4703. The method of claim 4681, further comprisingconverting at least a portion of the produced synthesis gas tocondensable hydrocarbons using a Fischer-Tropsch synthesis process.4704. The method of claim 4681, further comprising converting at least aportion of the produced synthesis gas to methanol.
 4705. The method ofclaim 4681, further comprising converting at least a portion of theproduced synthesis gas to gasoline.
 4706. The method of claim 4681,further comprising converting at least a portion of the synthesis gas tomethane using a catalytic methanation process.
 4707. The method of claim4681, further comprising providing heat from three or more heat sourcesto at least a portion of the formation, wherein three or more of theheat sources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 4708.The method of claim 4681, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 4709. A methodfor in situ production of synthesis gas from an oil shale formation,comprising: heating a portion of the formation with one or more heatsources to create increased and substantially uniform permeabilitywithin a portion of the formation and to raise a temperature within theportion to a temperature sufficient to allow synthesis gas generation;providing a synthesis gas generating fluid into the portion through atleast one injection wellbore to generate synthesis gas from hydrocarbonsand the synthesis gas generating fluid; and producing synthesis gas fromat least one heat source in which is positioned a heat source of the oneor more heat sources.
 4710. The method of claim 4709, wherein thetemperature sufficient to allow synthesis gas generation is within arange from about 400° C. to about 1200° C.
 4711. The method of claim4709, wherein creating a substantially uniform permeability comprisesheating the portion to a temperature within a range sufficient topyrolyze hydrocarbons within the portion, raising the temperature withinthe portion at a rate of less than about 5° C. per day duringpyrolyzation and removing a portion of pyrolyzed fluid from theformation.
 4712. The method of claim 4709, further comprising removingfluid from the formation through at least the one injection wellboreprior to heating the selected section to the temperature sufficient toallow synthesis gas generation.
 4713. The method of claim 4709, whereinthe injection wellbore comprises a wellbore of a heat source in which ispositioned a heat source of the one or more heat sources.
 4714. Themethod of claim 4709, further comprising heating the selected portionduring providing the synthesis gas generating fluid to inhibittemperature decrease in at least the portion of the selected section dueto synthesis gas generation.
 4715. The method of claim 4709, furthercomprising providing a portion of the heat needed to raise thetemperature sufficient to allow synthesis gas generation by convectingan oxidizing fluid to hydrocarbons within the selected section tooxidize a portion of the hydrocarbons and generate heat.
 4716. Themethod of claim 4709, further comprising controlling the heating of theselected section and provision of the synthesis gas generating fluid tomaintain a temperature within the selected section above the temperaturesufficient to generate synthesis gas.
 4717. The method of claim 4709,further comprising: monitoring a composition of the produced synthesisgas; and controlling heating of the selected section and provision ofthe synthesis gas generating fluid to maintain the composition of theproduced synthesis gas within a desired range.
 4718. The method of claim4709, wherein the synthesis gas generating fluid comprises liquid water.4719. The method of claim 4709, wherein the synthesis gas generatingfluid comprises steam.
 4720. The method of claim 4709, wherein thesynthesis gas generating fluid comprises steam to heat the selectedsection and to generate synthesis gas.
 4721. The method of claim 4709,wherein the synthesis gas generating fluid comprises water and carbondioxide, wherein the carbon dioxide inhibits production of carbondioxide from the selected section.
 4722. The method of claim 4721,wherein a portion of the carbon dioxide comprises carbon dioxide removedfrom the formation.
 4723. The method of claim 4709, wherein thesynthesis gas generating fluid comprises carbon dioxide, and wherein aportion of the carbon dioxide reacts with carbon in the formation togenerate carbon monoxide.
 4724. The method of claim 4723, wherein aportion of the carbon dioxide comprises carbon dioxide removed from theformation.
 4725. The method of claim 4709, wherein providing thesynthesis gas generating fluid to the selected section comprises raisinga water table of the formation to allow water to enter the selectedsection.
 4726. The method of claim 4709, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersless than 5, and wherein at least a portion of the hydrocarbons undergoa reaction within the selected section to increase a H₂ concentrationwithin the produced synthesis gas.
 4727. The method of claim 4709,wherein the synthesis gas generating fluid comprises water andhydrocarbons having carbon numbers greater than 4, and wherein at leasta portion of the hydrocarbons react within the selected section toincrease an energy content of the produced synthesis gas.
 4728. Themethod of claim 4709, further comprising maintaining a pressure withinthe formation during synthesis gas generation, and passing producedsynthesis gas through a turbine to generate electricity.
 4729. Themethod of claim 4709, further comprising generating electricity from thesynthesis gas using a fuel cell.
 4730. The method of claim 4709, furthercomprising generating electricity from the synthesis gas using a fuelcell, separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent portionof the formation.
 4731. The method of claim 4709, further comprisingusing a portion of the synthesis gas as a combustion fuel for heatingthe formation.
 4732. The method of claim 4709, further comprisingconverting at least a portion of the produced synthesis gas tocondensable hydrocarbons using a Fischer-Tropsch synthesis process.4733. The method of claim 4709, further comprising converting at least aportion of the produced synthesis gas to methanol.
 4734. The method ofclaim 4709, further comprising converting at least a portion of theproduced synthesis gas to gasoline.
 4735. The method of claim 4709,further comprising converting at least a portion of the synthesis gas tomethane using a catalytic methanation process.
 4736. The method of claim4709, wherein a temperature of at least the one heat source wellbore ismaintained at a temperature of less than approximately 700° C. toproduce a synthesis gas having a ratio of H₂ to carbon monoxide ofgreater than about
 2. 4737. The method of claim 4709, wherein atemperature of at least the one heat source wellbore is maintained at atemperature of greater than approximately 700° C. to produce a synthesisgas having a ratio of H₂ to carbon monoxide of less than about
 2. 4738.The method of claim 4709, wherein a temperature of at least the one heatsource wellbore is maintained at a temperature of approximately 700° C.to produce a synthesis gas having a ratio of H₂ to carbon monoxide ofapproximately
 2. 4739. The method of claim 4709, wherein a heat sourceof the one or more heat sources comprises an electrical heater. 4740.The method of claim 4709, wherein a heat source of the one or more heatsources comprises a natural distributed heater.
 4741. The method ofclaim 4709, wherein a heat source of the one or more heat sourcescomprises a flameless distributed combustor (FDC) heater, and whereinfluids are produced from the wellbore of the FDC heater through aconduit positioned within the wellbore.
 4742. The method of claim 4709,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 4743.The method of claim 4709, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 4744. A methodof treating an oil shale formation in situ, comprising: providing heatfrom one or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation such that the heat from the one ormore heat sources pyrolyzes at least a portion of the hydrocarboncontaining material within the selected section of the formation;producing pyrolysis products from the formation; heating a first portionof a formation with one or more heat sources to a temperature sufficientto allow generation of synthesis gas; providing a first synthesis gasgenerating fluid to the first portion to generate a first synthesis gas;removing a portion of the first synthesis gas from the formation;heating a second portion of a formation with one or more heat sources toa temperature sufficient to allow generation of synthesis gas having aH₂ to CO ratio greater than a H₂ to CO ratio of the first synthesis gas;providing a second synthesis gas generating component to the secondportion to generate a second synthesis gas; removing a portion of thesecond synthesis gas from the formation; and blending a portion of thefirst synthesis gas with a portion of the second synthesis gas toproduce a blended synthesis gas having a selected H₂ to CO ratio. 4745.The method of claim 4744, wherein the one or more heat sources compriseat least two heat sources, and wherein superposition of heat from atleast the two heat sources pyrolyzes at least some hydrocarbons withinthe selected section of the formation.
 4746. The method of claim 4744,wherein the first synthesis gas generating fluid and second synthesisgas generating fluid comprise the same component.
 4747. The method ofclaim 4744, further comprising controlling the temperature in the firstportion to control a composition of the first synthesis gas.
 4748. Themethod of claim 4744, further comprising controlling the temperature inthe second portion to control a composition of the second synthesis gas.4749. The method of claim 4744, wherein the selected ratio is controlledto be approximately 2:1 H₂ to CO.
 4750. The method of claim 4744,wherein the selected ratio is controlled to range from approximately1.8:1 to approximately 2.2:1 H₂ to CO.
 4751. The method of claim 4744,wherein the selected ratio is controlled to be approximately 3:1 H₂ toCO.
 4752. The method of claim 4744, wherein the selected ratio iscontrolled to range from approximately 2.8:1 to approximately 3.2:1 H₂to CO.
 4753. The method of claim 4744, further comprising providing atleast a portion of the produced blended synthesis gas to a condensablehydrocarbon synthesis process to produce condensable hydrocarbons. 4754.The method of claim 4753, wherein the condensable hydrocarbon synthesisprocess comprises a Fischer-Tropsch process.
 4755. The method of claim4754, further comprising cracking at least a portion of the condensablehydrocarbons to form middle distillates.
 4756. The method of claim 4744,further comprising providing at least a portion of the produced blendedsynthesis gas to a catalytic methanation process to produce methane.4757. The method of claim 4744, further comprising providing at least aportion of the produced blended synthesis gas to a methanol-synthesisprocess to produce methanol.
 4758. The method of claim 4744, furthercomprising providing at least a portion of the produced blendedsynthesis gas to a gasoline-synthesis process to produce gasoline. 4759.The method of claim 4744, wherein removing a portion of the secondsynthesis gas comprises withdrawing second synthesis gas through aproduction well, wherein a temperature of the production well adjacentto a second syntheses gas production zone is maintained at asubstantially constant temperature configured to produce secondsynthesis gas having the H₂ to CO ratio greater the first synthesis gas.4760. The method of claim 4744, wherein the first synthesis gasproducing fluid comprises CO₂ and wherein the temperature of the firstportion is at a temperature that will result in conversion of CO₂ andcarbon from the first portion to CO to generate a CO rich firstsynthesis gas.
 4761. The method of claim 4744, wherein the secondsynthesis gas producing fluid comprises water and hydrocarbons havingcarbon numbers less than 5, and wherein at least a portion of thehydrocarbons react within the formation to increase a H₂ concentrationwithin the produced second synthesis gas.
 4762. The method of claim4744, wherein blending a portion of the first synthesis gas with aportion of the second synthesis gas comprises producing an intermediatemixture having a H₂ to CO mixture of less than the selected ratio, andsubjecting the intermediate mixture to a shift reaction to reduce anamount of CO and increase an amount of H₂ to produce the selected ratioof H₂ to CO.
 4763. The method of claim 4744, further comprising removingan excess of first synthesis gas from the first portion to have anexcess of CO, subjecting the first synthesis gas to a shift reaction toreduce an amount of CO and increase an amount of H₂ before blending thefirst synthesis gas with the second synthesis gas.
 4764. The method ofclaim 4744, further comprising removing the first synthesis gas from theformation under pressure, and passing removed first synthesis gasthrough a turbine to generate electricity.
 4765. The method of claim4744, further comprising removing the second synthesis gas from theformation under pressure, and passing removed second synthesis gasthrough a turbine to generate electricity.
 4766. The method of claim4744, further comprising generating electricity from the blendedsynthesis gas using a fuel cell.
 4767. The method of claim 4744, furthercomprising generating electricity from the blended synthesis gas using afuel cell, separating carbon dioxide from a fluid exiting the fuel cell,and storing a portion of the separated carbon dioxide within a spentportion of the formation.
 4768. The method of claim 4744, furthercomprising using at least a portion of the blended synthesis gas as acombustion fuel for heating the formation.
 4769. The method of claim4744, further comprising allowing the heat to transfer from the one ormore heat sources to the selected section to substantially uniformlyincrease a permeability of the selected section.
 4770. The method ofclaim 4744, further comprising controlling heat transfer from the one ormore heat sources to produce a permeability within the selected sectionof greater than about 100 millidarcy.
 4771. The method of claim 4744,further comprising heating at least the portion of the selected sectionwhen providing the synthesis gas generating fluid to inhibit temperaturedecrease within the selected section during synthesis gas generation.4772. The method of claim 4744, wherein the temperature sufficient toallow synthesis gas generation is within a range from approximately 400°C. to approximately 1200° C.
 4773. The method of claim 4744, whereinheating the first a portion of the selected section to a temperaturesufficient to allow synthesis gas generation comprises: heating zonesadjacent to wellbores of one or more heat sources with heaters disposedin the wellbores, wherein the heaters are configured to raisetemperatures of the zones to temperatures sufficient to support reactionof hydrocarbon containing material within the zones with an oxidizingfluid; introducing the oxidizing fluid to the zones substantially bydiffusion; allowing the oxidizing fluid to react with at least a portionof the hydrocarbon containing material within the zones to produce heatin the zones; and transferring heat from the zones to the selectedsection.
 4774. The method of claim 4744, wherein heating the secondportion of the selected section to a temperature sufficient to allowsynthesis gas generation comprises: heating zones adjacent to wellboresof one or more heat sources with heaters disposed in the wellbores,wherein the heaters are configured to raise temperatures of the zones totemperatures sufficient to support reaction of hydrocarbon containingmaterial within the zones with an oxidizing fluid; introducing theoxidizing fluid to the zones substantially by diffusion; allowing theoxidizing fluid to react with at least a portion of the hydrocarboncontaining material within the zones to produce heat in the zones; andtransferring heat from the zones to the selected section.
 4775. Themethod of claim 4744, wherein heating the first portion of the selectedsection to a temperature sufficient to allow synthesis gas generationcomprises: introducing an oxidizing fluid into the formation through awellbore; transporting the oxidizing fluid substantially by convectioninto the first portion of the selected section, wherein the firstportion of the selected section is at a temperature sufficient tosupport an oxidation reaction with the oxidizing fluid; and reacting theoxidizing fluid within the first portion of the selected section togenerate heat and raise the temperature of the first portion.
 4776. Themethod of claim 4744, wherein heating the second portion of the selectedsection to a temperature sufficient to allow synthesis gas generationcomprises: introducing an oxidizing fluid into the formation through awellbore; transporting the oxidizing fluid substantially by convectioninto the second portion of the selected section, wherein the secondportion of the selected section is at a temperature sufficient tosupport an oxidation reaction with the oxidizing fluid; and reacting theoxidizing fluid within the second portion of the selected section togenerate heat and raise the temperature of the second portion.
 4777. Themethod of claim 4744, wherein the one or more heat sources comprise oneor more electrical heaters disposed in the formation.
 4778. The methodof claim 4744, wherein the one or more heat sources comprises one ormore natural distributed combustors.
 4779. The method of claim 4744,wherein the one or more heat sources comprise one or more heater wells,wherein at least one heater well comprises a conduit disposed within theformation, and further comprising heating the conduit by flowing a hotfluid through the conduit.
 4780. The method of claim 4744, whereinheating the first portion of the selected section to a temperaturesufficient to allow synthesis gas generation and providing a firstsynthesis gas generating fluid to the first portion of the selectedsection comprises introducing steam into the first portion.
 4781. Themethod of claim 4744, wherein heating the second portion of the selectedsection to a temperature sufficient to allow synthesis gas generationand providing a second synthesis gas generating fluid to the secondportion of the selected section comprises introducing steam into thesecond portion.
 4782. The method of claim 4744, further comprisingcontrolling the heating of the first portion of selected section andprovision of the first synthesis gas generating fluid to maintain atemperature within the first portion of the selected section above thetemperature sufficient to generate synthesis gas.
 4783. The method ofclaim 4744, further comprising controlling the heating of the secondportion of selected section and provision of the second synthesis gasgenerating fluid to maintain a temperature within the second portion ofthe selected section above the temperature sufficient to generatesynthesis gas.
 4784. The method of claim 4744, wherein the firstsynthesis gas generating fluid comprises liquid water.
 4785. The methodof claim 4744, wherein the second synthesis gas generating fluidcomprises liquid water.
 4786. The method of claim 4744, wherein thefirst synthesis gas generating fluid comprises steam.
 4787. The methodof claim 4744, wherein the second synthesis gas generating fluidcomprises s team.
 4788. The method of claim 4744, wherein the firstsynthesis gas generating fluid comprises water and carbon dioxide,wherein the carbon dioxide inhibits production of carbon dioxide fromthe selected section.
 4789. The method of claim 4788, wherein a portionof the carbon dioxide within the first synthesis gas generating fluidcomprises carbon dioxide removed from the formation.
 4790. The method ofclaim 4744, wherein the second synthesis gas generating fluid compriseswater and carbon dioxide, wherein the carbon dioxide inhibits productionof carbon dioxide from the selected section.
 4791. The method of claim4790, wherein a portion of the carbon dioxide within the secondsynthesis gas generating fluid comprises carbon dioxide removed from theformation.
 4792. The method of claim 4744, wherein the first synthesisgas generating fluid comprises carbon dioxide, and wherein a portion ofthe carbon dioxide reacts with carbon in the formation to generatecarbon monoxide.
 4793. The method of claim 4792, wherein a portion ofthe carbon dioxide within the first synthesis gas generating fluidcomprises carbon dioxide removed from the formation.
 4794. The method ofclaim 4744, wherein the second synthesis gas generating fluid comprisescarbon dioxide, and wherein a portion of the carbon dioxide reacts withcarbon in the formation to generate carbon monoxide.
 4795. The method ofclaim 4794, wherein a portion of the carbon dioxide within the secondsynthesis gas generating fluid comprises carbon dioxide removed from theformation.
 4796. The method of claim 4744, wherein providing the firstsynthesis gas generating fluid to the first portion of the selectedsection comprises raising a water table of the formation to allow waterto flow into the first portion of the selected section.
 4797. The methodof claim 4744, wherein providing the second synthesis gas generatingfluid to the second portion of the selected section comprises raising awater table of the formation to allow water to flow into the secondportion of the selected section.
 4798. The method of claim 4744, whereinthe first synthesis gas generating fluid comprises water andhydrocarbons having carbon numbers less than 5, and wherein at least aportion of the hydrocarbons are subjected to a reaction within the firstportion of the selected section to increase a H₂ concentration withinthe produced first synthesis gas.
 4799. The method of claim 4744,wherein the second synthesis gas generating fluid comprises water andhydrocarbons having carbon numbers less than 5, and wherein at least aportion of the hydrocarbons are subjected to a reaction within thesecond portion of the selected section to increase a H₂ concentrationwithin the produced second synthesis gas.
 4800. The method of claim4744, wherein the first synthesis gas generating fluid comprises waterand hydrocarbons having carbon numbers greater than 4, and wherein atleast a portion of the hydrocarbons react within the first portion ofthe selected section to increase an energy content of the produced firstsynthesis gas.
 4801. The method of claim 4744, wherein the secondsynthesis gas generating fluid comprises water and hydrocarbons havingcarbon numbers greater than 4, and wherein at least a portion of thehydrocarbons react within at least the second portion of the selectedsection to increase an energy content of the second produced synthesisgas.
 4802. The method of claim 4744, further comprising maintaining apressure within the formation during synthesis gas generation, andpassing produced blended synthesis gas through a turbine to generateelectricity.
 4803. The method of claim 4744, further comprisinggenerating electricity from the blended synthesis gas using a fuel cell.4804. The method of claim 4744, further comprising generatingelectricity from the blended synthesis gas using a fuel cell, separatingcarbon dioxide from a fluid exiting the fuel cell, and storing a portionof the separated carbon dioxide within a spent section of the formation.4805. The method of claim 4744, further comprising using a portion ofthe blended synthesis gas as a combustion fuel for the one or more heatsources.
 4806. The method of claim 4744, further comprising using aportion of the first synthesis gas as a combustion fuel for the one ormore heat sources.
 4807. The method of claim 4744, further comprisingusing a portion of the second synthesis gas as a combustion fuel for theone or more heat sources.
 4808. The method of claim 4744, furthercomprising using a portion of the blended synthesis gas as a combustionfuel for the one or more heat sources.
 4809. A method of treating an oilshale formation in situ, comprising: providing heat from one or moreheat sources to at least a portion of the formation; allowing the heatto transfer from the one or more heat sources to a selected section ofthe formation such that the heat from the one or more heat sourcespyrolyzes at least some of the hydrocarbons within the selected sectionof the formation; producing pyrolysis products from the formation;heating at least a portion of the selected section to a temperaturesufficient to generate synthesis gas; controlling a temperature of atleast a portion of the selected section to generate synthesis gas havinga selected H₂ to CO ratio; providing a synthesis gas generating fluid toat least the portion of the selected section to generate synthesis gas;and producing a portion of the synthesis gas from the formation. 4810.The method of claim 4809, wherein the one or more heat sources compriseat least two heat sources, and wherein superposition of heat from atleast the two heat sources pyrolyzes at least some hydrocarbons withinthe selected section of the formation.
 4811. The method of claim 4809,wherein the selected ratio is controlled to be approximately 2:1 H₂ toCO.
 4812. The method of claim 4809, wherein the selected ratio iscontrolled to range from approximately 1.8:1 to approximately 2.2:1 H₂to CO.
 4813. The method of claim 4809, wherein the selected ratio iscontrolled to be approximately 3:1 H₂ to CO.
 4814. The method of claim4809, wherein the selected ratio is controlled to range fromapproximately 2.8:1 to approximately 3.2:1 H₂ to CO.
 4815. The method ofclaim 4809, further comprising providing at least a portion of theproduced synthesis gas to a condensable hydrocarbon synthesis process toproduce condensable hydrocarbons.
 4816. The method of claim 4815,wherein the condensable hydrocarbon synthesis process comprises aFischer-Tropsch process.
 4817. The method of claim 4816, furthercomprising cracking at least a portion of the condensable hydrocarbonsto form middle distillates.
 4818. The method of claim 4809, furthercomprising providing at least a portion of the produced synthesis gas toa catalytic methanation process to produce methane.
 4819. The method ofclaim 4809, further comprising providing at least a portion of theproduced synthesis gas to a methanol-synthesis process to producemethanol.
 4820. The method of claim 4809, further comprising providingat least a portion of the produced synthesis gas to a gasoline-synthesisprocess to produce gasoline.
 4821. The method of claim 4809, furthercomprising allowing the heat to transfer from the one or more heatsources to the selected section to substantially uniformly increase apermeability of the selected section.
 4822. The method of claim 4809,further comprising controlling heat transfer from the one or more heatsources to produce a permeability within the selected section of greaterthan about 100 millidarcy.
 4823. The method of claim 4809, furthercomprising heating at least the portion of the selected section whenproviding the synthesis gas generating fluid to inhibit temperaturedecrease within the selected section during synthesis gas generation.4824. The method of claim 4809, wherein the temperature sufficient toallow synthesis gas generation is within a range from approximately 400°C. to approximately 1200° C.
 4825. The method of claim 4809, whereinheating at least the portion of the selected section to a temperaturesufficient to allow synthesis gas generation comprises: heating zonesadjacent to wellbores of one or more heat sources with heaters disposedin the wellbores, wherein the heaters are configured to raisetemperatures of the zones to temperatures sufficient to support reactionof hydrocarbon containing material within the zones with an oxidizingfluid; introducing the oxidizing fluid to the zones substantially bydiffusion; allowing the oxidizing fluid to react with at least a portionof the hydrocarbon containing material within the zones to produce heatin the zones; and transferring heat from the zones to the selectedsection.
 4826. The method of claim 4809, wherein heating at least theportion of the selected section to a temperature sufficient to allowsynthesis gas generation comprises: introducing an oxidizing fluid intothe formation through a wellbore; transporting the oxidizing fluidsubstantially by convection into the portion of the selected section,wherein the portion of the selected section is at a temperaturesufficient to support an oxidation reaction with the oxidizing fluid;and reacting the oxidizing fluid within the portion of the selectedsection to generate heat and raise the temperature of the portion. 4827.The method of claim 4809, wherein the one or more heat sources compriseone or more electrical heaters disposed in the formation.
 4828. Themethod of claim 4809, wherein the one or more heat sources comprises oneor more natural distributed combustors.
 4829. The method of claim 4809,wherein the one or more heat sources comprise one or more heater wells,wherein at least one heater well comprises a conduit disposed within theformation, and further comprising heating the conduit by flowing a hotfluid through the conduit.
 4830. The method of claim 4809, whereinheating at least the portion of the selected section to a temperaturesufficient to allow synthesis gas generation and providing a synthesisgas generating fluid to at least the portion of the selected sectioncomprises introducing steam into the portion.
 4831. The method of claim4809, further comprising controlling the heating of at least the portionof selected section and provision of the synthesis gas generating fluidto maintain a temperature within at least the portion of the selectedsection above the temperature sufficient to generate synthesis gas.4832. The method of claim 4809, wherein the synthesis gas generatingfluid comprises liquid water.
 4833. The method of claim 4809, whereinthe synthesis gas generating fluid comprises steam.
 4834. The method ofclaim 4809, wherein the synthesis gas generating fluid comprises waterand carbon dioxide, wherein the carbon dioxide inhibits production ofcarbon dioxide from the selected section.
 4835. The method of claim4834, wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.4836. The method of claim 4809, wherein the synthesis gas generatingfluid comprises carbon dioxide, and wherein a portion of the carbondioxide reacts with carbon in the formation to generate carbon monoxide.4837. The method of claim 4836, wherein a portion of the carbon dioxidewithin the synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 4838. The method of claim 4809, whereinproviding the synthesis gas generating fluid to at least the portion ofthe selected section comprises raising a water table of the formation toallow water to flow into the at least the portion of the selectedsection.
 4839. The method of claim 4809, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersless than 5, and wherein at least a portion of the hydrocarbons aresubjected to a reaction within at least the portion of the selectedsection to increase a H₂ concentration within the produced synthesisgas.
 4840. The method of claim 4809, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersgreater than 4, and wherein at least a portion of the hydrocarbons reactwithin at least the portion of the selected section to increase anenergy content of the produced synthesis gas.
 4841. The method of claim4809, further comprising maintaining a pressure within the formationduring synthesis gas generation, and passing produced synthesis gasthrough a turbine to generate electricity.
 4842. The method of claim4809, further comprising generating electricity from the synthesis gasusing a fuel cell.
 4843. The method of claim 4809, further comprisinggenerating electricity from the synthesis gas using a fuel cell,separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent sectionof the formation.
 4844. The method of claim 4809, further comprisingusing a portion of the synthesis gas as a combustion fuel for the one ormore heat sources.
 4845. A method of treating an oil shale formation insitu, comprising: providing heat from one or more heat sources to atleast a portion of the formation; allowing the heat to transfer from theone or more heat sources to a selected section of the formation suchthat the heat from the one or more heat sources pyrolyzes at least someof the hydrocarbons within the selected section of the formation;producing pyrolysis products from the formation; heating at least aportion of the selected section to a temperature sufficient to generatesynthesis gas; controlling a temperature in or proximate to a synthesisgas production well to generate synthesis gas having a selected H₂ to COratio; providing a synthesis gas generating fluid to at least theportion of the selected section to generate synthesis gas; and producingsynthesis gas from the formation.
 4846. The method of claim 4845,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 4847. The method of claim 4845, wherein the selected ratio iscontrolled to be approximately 2:1 H₂ to CO.
 4848. The method of claim4845, wherein the selected ratio is controlled to range fromapproximately 1.8:1 to approximately 2.2:1 H₂to CO.
 4849. The method ofclaim 4845, wherein the selected ratio is controlled to be approximately3:1 H₂ to CO.
 4850. The method of claim 4845, wherein the selected ratiois controlled to range from approximately 2.8:1 to approximately 3.2:1H₂ to CO.
 4851. The method of claim 4845, further comprising providingat least a portion of the produced synthesis gas to a condensablehydrocarbon synthesis process to produce condensable hydrocarbons. 4852.The method of claim 4851, wherein the condensable hydrocarbon synthesisprocess comprises a Fischer-Tropsch process.
 4853. The method of claim4852, further comprising cracking at least a portion of the condensablehydrocarbons to form middle distillates.
 4854. The method of claim 4845,further comprising providing at least a portion of the producedsynthesis gas to a catalytic methanation process to produce methane.4855. The method of claim 4845, further comprising providing at least aportion of the produced synthesis gas to a methanol-synthesis process toproduce methanol.
 4856. The method of claim 4845, further comprisingproviding at least a portion of the produced synthesis gas to agasoline-synthesis process to produce gasoline.
 4857. The method ofclaim 4845, further comprising allowing the heat to transfer from theone or more heat sources to the selected section to substantiallyuniformly increase a permeability of the selected section.
 4858. Themethod of claim 4845, further comprising controlling heat transfer fromthe one or more heat sources to produce a permeability within theselected section of greater than about 100 millidarcy.
 4859. The methodof claim 4845, further comprising heating at least the portion of theselected section when providing the synthesis gas generating fluid toinhibit temperature decrease within the selected section duringsynthesis gas generation.
 4860. The method of claim 4845, wherein thetemperature sufficient to allow synthesis gas generation is within arange from approximately 400° C. to approximately 1200° C.
 4861. Themethod of claim 4845, wherein heating at least the portion of theselected section to a temperature sufficient to allow synthesis gasgeneration comprises: heating zones adjacent to wellbores of one or moreheat sources with heaters disposed in the wellbores, wherein the heatersare configured to raise temperatures of the zones to temperaturessufficient to support reaction of hydrocarbon containing material withinthe zones with an oxidizing fluid; introducing the oxidizing fluid tothe zones substantially by diffusion; allowing the oxidizing fluid toreact with at least a portion of the hydrocarbon containing materialwithin the zones to produce heat in the zones; and transferring heatfrom the zones to the selected section.
 4862. The method of claim 4845,wherein heating at least the portion of the selected section to atemperature sufficient to allow synthesis gas generation comprises:introducing an oxidizing fluid into the formation through a wellbore;transporting the oxidizing fluid substantially by convection into theportion of the selected section, wherein the portion of the selectedsection is at a temperature sufficient to support an oxidation reactionwith the oxidizing fluid; and reacting the oxidizing fluid within theportion of the selected section to generate heat and raise thetemperature of the portion.
 4863. The method of claim 4845, wherein theone or more heat sources comprise one or more electrical heatersdisposed in the formation
 4864. The method of claim 4845, wherein theone or more heat sources comprises one or more natural distributedcombustors.
 4865. The method of claim 4845, wherein the one or more heatsources comprise one or more heater wells, wherein at least one heaterwell comprises a conduit disposed within the formation, and furthercomprising heating the conduit by flowing a hot fluid through theconduit.
 4866. The method of claim 4845, wherein heating at least theportion of the selected section to a temperature sufficient to allowsynthesis gas generation and providing a synthesis gas generating fluidto at least the portion of the selected section comprises introducingsteam into the portion.
 4867. The method of claim 4845, furthercomprising controlling the heating of at least the portion of selectedsection and provision of the synthesis gas generating fluid to maintaina temperature within at least the portion of the selected section abovethe temperature sufficient to generate synthesis gas.
 4868. The methodof claim 4845, wherein the synthesis gas generating fluid comprisesliquid water. 4869 The method of claim 4845, wherein the synthesis gasgenerating fluid comprises steam.
 4870. The method of claim 4845,wherein the synthesis gas generating fluid comprises water and carbondioxide, wherein the carbon dioxide inhibits production of carbondioxide from the selected section.
 4871. The method of claim 4870,wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.4872. The method of claim 4845, wherein the synthesis gas generatingfluid comprises carbon dioxide, and wherein a portion of the carbondioxide reacts with carbon in the formation to generate carbon monoxide.4873. The method of claim 4872, wherein a portion of the carbon dioxidewithin the synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 4874. The method of claim 4845, whereinproviding the synthesis gas generating fluid to at least the portion ofthe selected section comprises raising a water table of the formation toallow water to flow into the at least the portion of the selectedsection.
 4875. The method of claim 4845, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersless than 5, and wherein at least a portion of the hydrocarbons aresubjected to a reaction within at least the portion of the selectedsection to increase a H₂ concentration within the produced synthesisgas.
 4876. The method of claim 4845, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersgreater than 4, and wherein at least a portion of the hydrocarbons reactwithin at least the portion of the selected section to increase anenergy content of the produced synthesis gas.
 4877. The method of claim4845, further comprising maintaining a pressure within the formationduring synthesis gas generation, and passing produced synthesis gasthrough a turbine to generate electricity.
 4878. The method of claim4845, further comprising generating electricity from the synthesis gasusing a fuel cell.
 4879. The method of claim 4845, further comprisinggenerating electricity from the synthesis gas using a fuel cell,separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent sectionof the formation.
 4880. The method of claim 4845, further comprisingusing a portion of the synthesis gas as a combustion fuel for the one ormore heat sources.
 4881. A method of treating an oil shale formation insitu, comprising: providing heat from one or more heat sources to atleast a portion of the formation; allowing the heat to transfer from theone or more heat sources to a selected section of the formation suchthat the heat from the one or more heat sources pyrolyzes at least someof the hydrocarbons within the selected section of the formation;producing pyrolysis products from the formation; heating at least aportion of the selected section to a temperature sufficient to generatesynthesis gas; controlling a temperature of at least a portion of theselected section to generate synthesis gas having a H₂ to CO ratiodifferent than a selected H₂ to CO ratio; providing a synthesis gasgenerating fluid to at least the portion of the selected section togenerate synthesis gas; producing synthesis gas from the formation;providing at least a portion of the produced synthesis gas to a shiftprocess wherein an amount of carbon monoxide is converted to carbondioxide; and separating at least a portion of the carbon dioxide toobtain a gas having a selected H₂ to CO ratio.
 4882. The method of claim4881, wherein the one or more heat sources comprise at least two heatsources, and wherein superposition of heat from at least the two heatsources pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 4883. The method of claim 4881, wherein the selectedratio is controlled to be approximately 2:1 H₂ to CO.
 4884. The methodof claim 4881, wherein the selected ratio is controlled to range fromapproximately 1.8:1 to 2.2:1 H₂ to CO.
 4885. The method of claim 4881,wherein the selected ratio is controlled to be approximately 3:1 H₂ toCO.
 4886. The method of claim 4881, wherein the selected ratio iscontrolled to range from approximately 2.8:1 to 3.2:1 H₂ to CO. 4887.The method of claim 4881, further comprising providing at least aportion of the produced synthesis gas to a condensable hydrocarbonsynthesis process to produce condensable hydrocarbons.
 4888. The methodof claim 4887, wherein the condensable hydrocarbon synthesis processcomprises a Fischer-Tropsch process.
 4889. The method of claim 4888,further comprising cracking at least a portion of the condensablehydrocarbons to form middle distillates.
 4890. The method of claim 4881,further comprising providing at least a portion of the producedsynthesis gas to a catalytic methanation process to produce methane.4891. The method of claim 4881, further comprising providing at least aportion of the produced synthesis gas to a methanol-synthesis process toproduce methanol.
 4892. The method of claim 4881, further comprisingproviding at least a portion of the produced synthesis gas to agasoline-synthesis process to produce gasoline.
 4893. The method ofclaim 4881, further comprising allowing the heat to transfer from theone or more heat sources to the selected section to substantiallyuniformly increase a permeability of the selected section.
 4894. Themethod of claim 4881, further comprising controlling heat transfer fromthe one or more heat sources to produce a permeability within theselected section of greater than about 100 millidarcy.
 4895. The methodof claim 4881, further comprising heating at least the portion of theselected section when providing the synthesis gas generating fluid toinhibit temperature decrease within the selected section duringsynthesis gas generation.
 4896. The method of claim 4881, wherein thetemperature sufficient to allow synthesis gas generation is within arange from approximately 400° C. to approximately 1200° C.
 4897. Themethod of claim 4881, wherein heating at least the portion of theselected section to a temperature sufficient to allow synthesis gasgeneration comprises: heating zones adjacent to wellbores of one or moreheat sources with heaters disposed in the wellbores, wherein the heatersare configured to raise temperatures of the zones to temperaturessufficient to support reaction of hydrocarbon containing material withinthe zones with an oxidizing fluid; introducing the oxidizing fluid tothe zones substantially by diffusion; allowing the oxidizing fluid toreact with at least a portion of the hydrocarbon containing materialwithin the zones to produce heat in the zones; and transferring heatfrom the zones to the selected section.
 4898. The method of claim 4881,wherein heating at least the portion of the selected section to atemperature sufficient to allow synthesis gas generation comprises:introducing an oxidizing fluid into the formation through a wellbore;transporting the oxidizing fluid substantially by convection into theportion of the selected section, wherein the portion of the selectedsection is at a temperature sufficient to support an oxidation reactionwith the oxidizing fluid; and reacting the oxidizing fluid within theportion of the selected section to generate heat and raise thetemperature of the portion.
 4899. The method of claim 4881, wherein theone or more heat sources comprise one or more electrical heatersdisposed in the formation.
 4900. The method of claim 4881, wherein theone or more heat sources comprises one or more natural distributedcombustors.
 4901. The method of claim 4881, wherein the one or more heatsources comprise one or more heater wells, wherein at least one heaterwell comprises a conduit disposed within the formation, and furthercomprising heating the conduit by flowing a hot fluid through theconduit.
 4902. The method of claim 4881, wherein heating at least theportion of the selected section to a temperature sufficient to allowsynthesis gas generation and providing a synthesis gas generating fluidto at least the portion of the selected section comprises introducingsteam into the portion.
 4903. The method of claim 4881, furthercomprising controlling the heating of at least the portion of selectedsection and provision of the synthesis gas generating fluid to maintaina temperature within at least the portion of the selected section abovethe temperature sufficient to generate synthesis gas.
 4904. The methodof claim 4881, wherein the synthesis gas generating fluid comprisesliquid water.
 4905. The method of claim 4881, wherein the synthesis gasgenerating fluid comprises steam.
 4906. The method of claim 4881,wherein the synthesis gas generating fluid comprises water and carbondioxide, wherein the carbon dioxide inhibits production of carbondioxide from the selected section.
 4907. The method of claim 4906,wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.4908. The method of claim 4881, wherein the synthesis gas generatingfluid comprises carbon dioxide, and wherein a portion of the carbondioxide reacts with carbon in the formation to generate carbon monoxide.4909. The method of claim 4908, wherein a portion of the carbon dioxidewithin the synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 4910. The method of claim 4881, whereinproviding the synthesis gas generating fluid to at least the portion ofthe selected section comprises raising a water table of the formation toallow water to flow into the at least the portion of the selectedsection.
 4911. The method of claim 4881, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersless than 5, and wherein at least a portion of the hydrocarbons aresubjected to a reaction within at least the portion of the selectedsection to increase a H₂ concentration within the produced synthesisgas.
 4912. The method of claim 4881, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersgreater than 4, and wherein at least a portion of the hydrocarbons reactwithin at least the portion of the selected section to increase anenergy content of the produced synthesis gas.
 4913. The method of claim4881, further comprising maintaining a pressure within the formationduring synthesis gas generation, and passing produced synthesis gasthrough a turbine to generate electricity.
 4914. The method of claim4881, further comprising generating electricity from the synthesis gasusing a fuel cell.
 4915. The method of claim 4881, further comprisinggenerating electricity from the synthesis gas using a fuel cell,separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent sectionof the formation.
 4916. The method of claim 4881, further comprisingusing a portion of the synthesis gas as a combustion fuel for the one ormore heat sources.
 4917. A method of forming a spent portion offormation within an oil shale formation, comprising: heating a firstportion of the formation to pyrolyze hydrocarbons within the firstportion and to establish a substantially uniform permeability within thefirst portion; and cooling the first portion.
 4918. The method of claim4917, wherein heating the first portion comprises transferring heat tothe first portion from one or more electrical heaters.
 4919. The methodof claim 4917, wherein heating the first portion comprises transferringheat to the first portion from one or more natural distributedcombustors.
 4920. The method of claim 4917, wherein heating the firstportion comprises transferring heat to the first portion from one ormore flameless distributed combustors.
 4921. The method of claim 4917,wherein heating the first portion comprises transferring heat to thefirst portion from heat transfer fluid flowing within one or morewellbores within the formation.
 4922. The method of claim 4921, whereinthe heat transfer fluid comprises steam.
 4923. The method of claim 4921,wherein the heat transfer fluid comprises combustion products from aburner.
 4924. The method of claim 4917, wherein heating the firstportion comprises transferring heat to the first portion from at leasttwo heater wells positioned within the formation, wherein the at leasttwo heater wells are placed in a substantially regular pattern, whereinthe substantially regular pattern comprises repetition of a base heaterunit, and wherein the base heater unit is formed of a number of heaterwells.
 4925. The method of claim 4924, wherein a spacing between a pairof adjacent heater wells is within a range from about 6 m to about 15 m.4926. The method of claim 4924, further comprising removing fluid fromthe formation through one or more production wells.
 4927. The method ofclaim 4926, wherein the one or more production wells are located in apattern, and wherein the one or more production wells are positionedsubstantially at centers of base heater units.
 4928. The method of claim4924, wherein the heater unit comprises three heater wells positionedsubstantially at apexes of an equilateral triangle.
 4929. The method ofclaim 4924, wherein the heater unit comprises four heater wellspositioned substantially at apexes of a rectangle.
 4930. The method ofclaim 4924, wherein the heater unit comprises five heater wellspositioned substantially at apexes of a regular pentagon.
 4931. Themethod of claim 4924, wherein the heater unit comprises six heater wellspositioned substantially at apexes of a regular hexagon.
 4932. Themethod of claim 4917, further comprising introducing water to the firstportion to cool the formation.
 4933. The method of claim 4917, furthercomprising removing steam from the formation.
 4934. The method of claim4933, further comprising using a portion of the removed steam to heat asecond portion of the formation.
 4935. The method of claim 4917, furthercomprising removing pyrolyzation products from the formation.
 4936. Themethod of claim 4917, further comprising generating synthesis gas withinthe portion by introducing a synthesis gas generating fluid into theportion, and removing synthesis gas from the formation.
 4937. The methodof claim 4917, further comprising heating a second section of theformation to pyrolyze hydrocarbons within the second portion, removingpyrolyzation fluid from the second portion, and storing a portion of theremoved pyrolyzation fluid within the first portion.
 4938. The method ofclaim 4937, wherein the portion of the removed pyrolyzation fluid isstored within the first portion when surface facilities that process theremoved pyrolyzation fluid are not able to process the portion of theremoved pyrolyzation fluid.
 4939. The method of claim 4937, furthercomprising heating the first portion to facilitate removal of the storedpyrolyzation fluid from the first portion.
 4940. The method of claim4917, further comprising generating synthesis gas within a secondportion of the formation, removing synthesis gas from the secondportion, and storing a portion of the removed synthesis gas within thefirst portion.
 4941. The method of claim 4940, wherein the portion ofthe removed synthesis gas from the second portion is stored within thefirst portion when surface facilities that process the removed synthesisgas are not able to process the portion of the removed synthesis gas.4942. The method of claim 4940, further comprising heating the firstportion to facilitate removal of the stored synthesis gas from the firstportion.
 4943. The method of claim 4917, further comprising removing atleast a portion of hydrocarbon containing material in the first portionand, further comprising using at least a portion of the hydrocarboncontaining material removed from the formation in a metallurgicalapplication.
 4944. The method of claim 4943, wherein the metallurgicalapplication comprises steel manufacturing.
 4945. A method ofsequestering carbon dioxide within an oil shale formation, comprising:heating a portion of the formation to increase permeability and form asubstantially uniform permeability within the portion; allowing theportion to cool; and storing carbon dioxide within the portion. 4946.The method of claim 4945, wherein the permeability of the portion isincreased to over 100 millidarcy.
 4947. The method of claim 4945,further comprising raising a water level within the portion to inhibitmigration of the carbon dioxide from the portion.
 4948. The method ofclaim 4945, further comprising heating the portion to release carbondioxide, and removing carbon dioxide from the portion.
 4949. The methodof claim 4945, further comprising pyrolyzing hydrocarbons within theportion during heating of the portion, and removing pyrolyzation productfrom the formation.
 4950. The method of claim 4945, further comprisingproducing synthesis gas from the portion during the heating of theportion, and removing synthesis gas from the formation.
 4951. The methodof claim 4945, wherein heating the portion comprises: heatinghydrocarbon containing material adjacent to one or more wellbores to atemperature sufficient to support oxidation of the hydrocarboncontaining material with an oxidizing fluid; introducing the oxidizingfluid to hydrocarbon containing material adjacent to the one or morewellbores to oxidize the hydrocarbons and produce heat; and conveyingproduced heat to the portion.
 4952. The method of claim 4951, whereinheating hydrocarbon containing material adjacent to the one or morewellbores comprises electrically heating the hydrocarbon containingmaterial.
 4953. The method of claim 4951, wherein the temperaturesufficient to support oxidation is in a range from approximately 200° C.to approximately 1200° C.
 4954. The method of claim 4945, whereinheating the portion comprises circulating heat transfer fluid throughone or more heating wells within the formation.
 4955. The method ofclaim 4954, wherein the heat transfer fluid comprises combustionproducts from a burner.
 4956. The method of claim 4954, wherein the heattransfer fluid comprises steam.
 4957. The method of claim 4945, furthercomprising removing fluid from the formation during heating of theformation, and combusting a portion of the removed fluid to generateheat to heat the formation.
 4958. The method of claim 4945, furthercomprising using at least a portion of the carbon dioxide forhydrocarbon bed demethanation prior to storing the carbon dioxide withinthe portion.
 4959. The method of claim 4945, further comprising using aportion of the carbon dioxide for enhanced oil recovery prior to storingthe carbon dioxide within the portion.
 4960. The method of claim 4945,wherein at least a portion of the carbon dioxide comprises carbondioxide generated in a fuel cell.
 4961. The method of claim 4945,wherein at least a portion of the carbon dioxide comprises carbondioxide formed as a combustion product.
 4962. The method of claim 4945,further comprising allowing the portion to cool by introducing water tothe portion; and removing the water from the formation as steam. 4963.The method of claim 4962, further comprising using the steam as a heattransfer fluid to heat a second portion of the formation.
 4964. Themethod of claim 4945, wherein storing carbon dioxide in the portioncomprises adsorbing carbon dioxide to hydrocarbon containing materialwithin the formation.
 4965. The method of claim 4945, wherein storingcarbon dioxide comprises passing a first fluid stream comprising thecarbon dioxide and other fluid through the portion; adsorbing carbondioxide onto hydrocarbon containing material within the formation; andremoving a second fluid stream from the formation, wherein aconcentration of the other fluid in the second fluid stream is greaterthan concentration of other fluid in the first stream due to the absenceof the adsorbed carbon dioxide in the second stream.
 4966. The method ofclaim 4945, wherein an amount of carbon dioxide stored within theportion is equal to or greater than an amount of carbon dioxidegenerated within the portion and removed from the formation duringheating of the portion.
 4967. The method of claim 4945, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, and wherein the unitof heat sources comprises a triangular pattern.
 4968. The method ofclaim 4945, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,wherein the unit of heat sources comprises a triangular pattern, andwherein a plurality of the units are repeated over an area of theformation to form a repetitive pattern of units.
 4969. A method of insitu sequestration of carbon dioxide within an oil shale formation insitu, comprising: providing heat from one or more heat sources to atleast a first portion of the formation; allowing the heat to transferfrom one or more sources to a selected section of the formation suchthat the heat from the one or more heat sources pyrolyzes at least someof the hydrocarbons within the selected section of the formation;producing pyrolyzation fluids, wherein the pyrolyzation fluids comprisecarbon dioxide; and storing an amount of carbon dioxide in theformation, wherein the amount of stored carbon dioxide is equal to orgreater than an amount of carbon dioxide within the pyrolyzation fluids.4970. The method of claim 4969, wherein the one or more heat sourcescomprise at least two heat sources, and wherein superposition of heatfrom at least the two heat sources pyrolyzes at least some hydrocarbonswithin the selected section of the formation.
 4971. The method of claim4969, wherein the carbon dioxide is stored within a spent portion of theformation.
 4972. The method of claim 4969, wherein a portion of thecarbon dioxide stored within the formation is carbon dioxide separatedfrom the pyrolyzation fluids.
 4973. The method of claim 4969, furthercomprising separating a portion of carbon dioxide from the pyrolyzationfluids, and using the carbon dioxide as a flooding agent in enhanced oilrecovery.
 4974. The method of claim 4969, further comprising separatinga portion of carbon dioxide from the pyrolyzation fluids, and using thecarbon dioxide as a synthesis gas generating fluid for the generation ofsynthesis gas from a section of the formation that is heated to atemperature sufficient to generate synthesis gas upon introduction ofthe synthesis gas generating fluid.
 4975. The method of claim 4969,further comprising separating a portion of carbon dioxide from thepyrolyzation fluids, and using the carbon dioxide to displacehydrocarbon bed methane.
 4976. The method of claim 4975, wherein thehydrocarbon bed is a deep hydrocarbon bed located over 760 m belowground surface.
 4977. The method of claim 4975, further comprisingadsorbing a portion of the carbon dioxide within the hydrocarbon bed.4978. The method of claim 4969, further comprising using at least aportion of the pyrolyzation fluids as a feed stream for a fuel cell.4979. The method of claim 4978, wherein the fuel cell generates carbondioxide, and further comprising storing an amount of carbon dioxideequal to or greater than an amount of carbon dioxide generated by thefuel cell within the formation.
 4980. The method of claim 4969, whereina spent portion of the formation comprises hydrocarbon containingmaterial within a section of the formation that has been heated and fromwhich condensable hydrocarbons have been produced, and wherein the spentportion of the formation is at a temperature at which carbon dioxideadsorbs onto the hydrocarbon containing material.
 4981. The method ofclaim 4969, further comprising raising a water level within the spentportion to inhibit migration of the carbon dioxide from the portion.4982. The method of claim 4969, wherein producing fluids from theformation comprises removing pyrolyzation products from the formation.4983. The method of claim 4969, wherein producing fluids from theformation comprises heating the selected section to a temperaturesufficient to generate synthesis gas; introducing a synthesis gasgenerating fluid into the selected section; and removing synthesis gasfrom the formation.
 4984. The method of claim 4983, wherein thetemperature sufficient to generate synthesis gas ranges from about 400°C. to about 1200° C.
 4985. The method of claim 4983, wherein heating theselected section comprises introducing an oxidizing fluid into theselected section, reacting the oxidizing fluid within the selectedsection to heat the selected section.
 4986. The method of claim 4983,wherein heating the selected section comprises: heating hydrocarboncontaining material adjacent to one or more wellbores to a temperaturesufficient to support oxidation of the hydrocarbon containing materialwith an oxidant; introducing the oxidant to hydrocarbon containingmaterial adjacent to the one or more wellbores to oxidize thehydrocarbons and produce heat; and conveying produced heat to theportion.
 4987. The method of claim 4969, wherein the spent portion ofthe formation comprises a substantially uniform permeability created byheating the spent formation and removing fluid during formation of thespent portion.
 4988. The method of claim 4969, wherein the one or moreheat sources comprise electrical heaters.
 4989. The method of claim4969, wherein the one or more heat sources comprise flamelessdistributed combustors.
 4990. The method of claim 4989, wherein aportion of fuel for the one or more flameless distributed combustors isobtained from the formation.
 4991. The method of claim 4969, wherein theone or more heat sources comprise heater wells in the formation throughwhich heat transfer fluid is circulated.
 4992. The method of claim 4991,wherein the heat transfer fluid comprises combustion products.
 4993. Themethod of claim 4991, wherein the heat transfer fluid comprises steam.4994. The method of claim 4969, wherein condensable hydrocarbons areproduced under pressure, and further comprising generating electricityby passing a portion of the produced fluids through a turbine.
 4995. Themethod of claim 4969, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, and wherein the unit of heat sources comprises atriangular pattern.
 4996. The method of claim 4969, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 4997. A method for in situ production of energy froman oil shale formation, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation such that the heat from the one or more heat sources pyrolyzesat least a portion of the hydrocarbons within the selected section ofthe formation; producing pyrolysis products from the formation;providing at least a portion of the pyrolysis products to a reformer togenerate synthesis gas; producing the synthesis gas from the reformer;providing at least a portion of the produced synthesis gas to a fuelcell to produce electricity, wherein the fuel cell produces a carbondioxide containing exit stream; and storing at least a portion of thecarbon dioxide in the carbon dioxide containing exit stream in asubsurface formation.
 4998. The method of claim 4997, wherein the one ormore heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.4999. The method of claim 4997, wherein at least a portion of thepyrolysis products are used as fuel in the reformer.
 5000. The method ofclaim 4997, wherein the synthesis gas comprises substantially H₂. 5001.The method of claim 4997, wherein the subsurface formation is a spentportion of the formation.
 5002. The method of claim 4997, wherein thesubsurface formation is an oil reservoir.
 5003. The method of claim5002, wherein at least a portion of the carbon dioxide is used as adrive fluid for enhanced oil recovery in the oil reservoir.
 5004. Themethod of claim 4997, wherein the subsurface formation is a coalformation.
 5005. The method of claim 5004, wherein at least a portion ofthe carbon dioxide is used to produce methane from the coal formation.5006. The method of claim 5005, further comprising sequestering at leasta portion of the carbon dioxide within the coal formation.
 5007. Themethod of claim 4997, wherein the reformer produces a reformer carbondioxide containing exit stream.
 5008. The method of claim 4997, furthercomprising storing at least a portion of the carbon dioxide in thereformer carbon dioxide containing exit stream in the subsurfaceformation.
 5009. The method of claim 5008, wherein the subsurfaceformation is a spent portion of the formation.
 5010. The method of claim5008, wherein the subsurface formation is an oil reservoir.
 5011. Themethod of claim 5010, wherein at least a portion of the carbon dioxidein the reformer carbon dioxide containing exit stream is used as a drivefluid for enhanced oil recovery in the oil reservoir.
 5012. The methodof claim 5008, wherein the subsurface formation is a coal formation.5013. The method of claim 5012, wherein at least a portion of the carbondioxide in the reformer carbon dioxide containing exit stream is used toproduce methane from the coal formation.
 5014. The method of claim 5012,wherein the coal formation is located over about 760 m below groundsurface.
 5015. The method of claim 5013, further comprising sequesteringat least a portion of the carbon dioxide in the reformer carbon dioxidecontaining exit stream within the coal formation.
 5016. The method ofclaim 4997, wherein the fuel cell is a molten carbonate fuel cell. 5017.The method of claim 4997, wherein the fuel cell is a solid oxide fuelcell.
 5018. The method of claim 4997, further comprising using a portionof the produced electricity to power electrical heaters within theformation.
 5019. The method of claim 4997, further comprising using aportion of the produced pyrolysis products as a feed stream for the fuelcell.
 5020. The method of claim 4997, wherein the one or more heatsources comprise one or more electrical heaters disposed in theformation.
 5021. The method of claim 4997, wherein the one or more heatsources comprise one or more flameless distributed combustors disposedin the formation.
 5022. The method of claim 5021, wherein a portion offuel for the flameless distributed combustors is obtained from theformation.
 5023. The method of claim 4997, wherein the one or more heatsources comprise one or more heater wells, wherein at least one heaterwell comprises a conduit disposed within the formation, and furthercomprising heating the conduit by flowing a hot fluid through theconduit.
 5024. The method of claim 4997, further comprising using aportion of the synthesis gas as a combustion fuel for the one or moreheat sources.
 5025. A method for producing ammonia using an oil shaleformation, comprising: separating air to produce an O₂ rich stream and aN₂ rich stream; heating a selected section of the formation to atemperature sufficient to support reaction of hydrocarbon containingmaterial in the formation to form synthesis gas; providing synthesis gasgenerating fluid and at least a portion of the O₂ rich stream to theselected section; allowing the synthesis gas generating fluid and O₂ inthe O₂ rich stream to react with at least a portion of the hydrocarboncontaining material in the formation to generate synthesis gas;producing synthesis gas from the formation, wherein the synthesis gascomprises H₂ and CO; providing at least a portion of the H₂ in thesynthesis gas to an ammonia synthesis process; providing N₂ to theammonia synthesis process; and using the ammonia synthesis process togenerate ammonia.
 5026. The method of claim 5025, wherein the ratio ofthe H₂ to N₂ provided to the ammonia synthesis process is approximately3:1.
 5027. The method of claim 5025, wherein the ratio of the H₂ to N₂provided to the ammonia synthesis process ranges from approximately2.8:1 to approximately 3.2:1.
 5028. The method of claim 5025, whereinthe temperature sufficient to support reaction of hydrocarbon containingmaterial in the formation to form synthesis gas ranges fromapproximately 400° C. to approximately 1200° C.
 5029. The method ofclaim 5025, further comprising separating at least a portion of carbondioxide in the synthesis gas from at least a portion of the synthesisgas.
 5030. The method of claim 5029, wherein the carbon dioxide isseparated from the synthesis gas by an amine separator.
 5031. The methodof claim 5030, further comprising providing at least a portion of thecarbon dioxide to a urea synthesis process to produce urea.
 5032. Themethod of claim 5025, wherein at least a portion of the N₂ stream isused to condense hydrocarbons with 4 or more carbon atoms from apyrolyzation fluid.
 5033. The method of claim 5025, wherein at least aportion of the N₂ rich stream is provided to the ammonia synthesisprocess.
 5034. The method of claim 5025, wherein the air is separated bycryogenic distillation.
 5035. The method of claim 5025, wherein the airis separated by membrane separation.
 5036. The method of claim 5025,wherein fluids produced during pyrolysis of an oil shale formationcomprise ammonia and, further comprising adding at least a portion ofsuch ammonia to the ammonia generated from the ammonia synthesisprocess.
 5037. The method of claim 5025, wherein fluids produced duringpyrolysis of a hydrocarbon formation are hydrotreated and at least someammonia is produced during hydrotreating, and, further comprising addingat least a portion of such ammonia to the ammonia generated from theammonia synthesis process.
 5038. The method of claim 5025, furthercomprising providing at least a portion of the ammonia to a ureasynthesis process to produce urea.
 5039. The method of claim 5025,further comprising providing at least a portion of the ammonia to a ureasynthesis process to produce urea and, further comprising providingcarbon dioxide from the formation to the urea synthesis process. 5040.The method of claim 5025, further comprising providing at least aportion of the ammonia to a urea synthesis process to produce urea and,further comprising shifting at least a portion of the carbon monoxide tocarbon dioxide in a shift process, and further comprising providing atleast a portion of the carbon dioxide from the shift process to the ureasynthesis process.
 5041. The method of claim 5025, wherein heating theselected section of the formation to a temperature to support reactionof hydrocarbon containing material in the formation to form synthesisgas comprises: heating zones adjacent to wellbores of one or more heatsources with heaters disposed in the wellbores, wherein the heaters areconfigured to raise temperatures of the zones to temperatures sufficientto support reaction of hydrocarbon containing material within the zoneswith O₂ in the O₂ rich stream; introducing the O₂ to the zonessubstantially by diffusion; allowing O₂ in the O₂ rich stream to reactwith at least a portion of the hydrocarbon containing material withinthe zones to produce heat in the zones; and transferring heat from thezones to the selected section.
 5042. The method of claim 5041, whereintemperatures sufficient to support reaction of hydrocarbon containingmaterial within the zones with O₂ range from approximately 200° C. toapproximately 1200° C.
 5043. The method of claim 5041, wherein the oneor more heat sources comprises one or more electrical heaters disposedin the formation.
 5044. The method of claim 5041, wherein the one ormore heat sources comprises one or more natural distributed combustors.5045. The method of claim 5041, wherein the one or more heat sourcescomprise one or more heater wells, wherein at least one heater wellcomprises a conduit disposed within the formation, and furthercomprising heating the conduit by flowing a hot fluid through theconduit.
 5046. The method of claim 5041, further comprising using aportion of the synthesis gas as a combustion fuel for the one or moreheat sources.
 5047. The method of claim 5025, wherein heating theselected section of the formation to a temperature to support reactionof hydrocarbon containing material in the formation to form synthesisgas comprises: introducing the O₂ rich stream into the formation througha wellbore; transporting O₂ in the O₂ rich stream substantially byconvection into the portion of the selected section, wherein the portionof the selected section is at a temperature sufficient to support anoxidation reaction with O₂ in the O₂ rich stream; and reacting the O₂within the portion of the selected section to generate heat and raisethe temperature of the portion.
 5048. The method of claim 5047, whereinthe temperature sufficient to support an oxidation reaction with O₂ranges from approximately 200° C. to approximately 1200° C.
 5049. Themethod of claim 5047, wherein the one or more heat sources comprises oneor more electrical heaters disposed in the formation.
 5050. The methodof claim 5047, wherein the one or more heat sources comprises one ormore natural distributed combustors.
 5051. The method of claim 5047,wherein the one or more heat sources comprise one or more heater wells,wherein at least one heater well comprises a conduit disposed within theformation, and further comprising heating the conduit by flowing a hotfluid through the conduit.
 5052. The method of claim 5047, furthercomprising using a portion of the synthesis gas as a combustion fuel forthe one or more heat sources.
 5053. The method of claim 5025, furthercomprising controlling the heating of at least the portion of theselected section and provision of the synthesis gas generating fluid tomaintain a temperature within at least the portion of the selectedsection above the temperature sufficient to generate synthesis gas.5054. The method of claim 5025, wherein the synthesis gas generatingfluid comprises liquid water.
 5055. The method of claim 5025, whereinthe synthesis gas generating fluid comprises steam.
 5056. The method ofclaim 5025, wherein the synthesis gas generating fluid comprises waterand carbon dioxide wherein the carbon dioxide inhibits production ofcarbon dioxide from the selected section.
 5057. The method of claim5056, wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.5058. The method of claim 5025, wherein the synthesis gas generatingfluid comprises carbon dioxide, and wherein a portion of the carbondioxide reacts with carbon in the formation to generate carbon monoxide.5059. The method of claim 5058, wherein a portion of the carbon dioxidewithin the synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 5060. The method of claim 5025, whereinproviding the synthesis gas generating fluid to at least the portion ofthe selected section comprises raising a water table of the formation toallow water to flow into the at least the portion of the selectedsection.
 5061. A method for producing ammonia using an oil shaleformation, comprising: generating a first ammonia feed stream from afirst portion of the formation; generating a second ammonia feed streamfrom a second portion of the formation, wherein the second ammonia feedstream has a H₂ to N₂ ratio greater than a H₂ to N₂ ratio of the firstammonia feed stream; blending at least a portion of the first ammoniafeed stream with at least a portion of the second ammonia feed stream toproduce a blended ammonia feed stream having a selected H₂ to N₂ ratio;providing the blended ammonia feed stream to an ammonia synthesisprocess; and using the ammonia synthesis process to generate ammonia.5062. The method of claim 5061, wherein the selected ratio isapproximately 3:1.
 5063. The method of claim 5061, wherein the selectedratio ranges from approximately 2.8:1 to approximately 3.2:1.
 5064. Themethod of claim 5061, further comprising separating at least a portionof carbon dioxide in the first ammonia feed stream from at least aportion of the first ammonia feed stream.
 5065. The method of claim5064, wherein the carbon dioxide is separated from the first ammoniafeed stream by an amine separator.
 5066. The method of claim 5065,further comprising providing at least a portion of the carbon dioxide toa urea synthesis process.
 5067. The method of claim 5061, furthercomprising separating at least a portion of carbon dioxide in theblended ammonia feed stream from at least a portion of the blendedammonia feed stream.
 5068. The method of claim 5067, wherein the carbondioxide is separated from the blended ammonia feed stream by an amineseparator.
 5069. The method of claim 5068, further comprising providingat least a portion of the carbon dioxide to a urea synthesis process.5070. The method of claim 5061, further comprising separating at least aportion of carbon dioxide in the second ammonia feed stream from atleast a portion of the second ammonia feed stream.
 5071. The method ofclaim 5070, wherein the carbon dioxide is separated from the secondammonia feed stream by an amine separator.
 5072. The method of claim5071, further comprising providing at least a portion of the carbondioxide to a urea synthesis process.
 5073. The method of claim 5061,wherein fluids produced during pyrolysis of an oil shale formationcomprise ammonia and, further comprising adding at least a portion ofsuch ammonia to the ammonia generated from the ammonia synthesisprocess.
 5074. The method of claim 5061, wherein fluids produced duringpyrolysis of a hydrocarbon formation are hydrotreated and at least someammonia is produced during hydrotreating, and further comprising addingat least a portion of such ammonia to the ammonia generated from theammonia synthesis process.
 5075. The method of claim 5061, furthercomprising providing at least a portion of the ammonia to a ureasynthesis process to produce urea.
 5076. The method of claim 5061,further comprising providing at least a portion of the ammonia to a ureasynthesis process to produce urea and, further comprising providingcarbon dioxide from the formation to the urea synthesis process. 5077.The method of claim 5061, further comprising providing at least aportion of the ammonia to a urea synthesis process to produce urea andfurther comprising shifting at least a portion of carbon monoxide in theblended ammonia feed stream to carbon dioxide in a shift process, andfurther comprising providing at least a portion of the carbon dioxidefrom the shift process to the urea synthesis process.
 5078. A method forproducing ammonia using an oil shale formation, comprising: heating aselected section of the formation to a temperature sufficient to supportreaction of hydrocarbon containing material in the formation to formsynthesis gas; providing a synthesis gas generating fluid and an O₂ richstream to the selected section, wherein the amount of N₂ in the O₂ richstream is sufficient to generate synthesis gas having a selected ratioof H₂ to N₂; allowing the synthesis gas generating fluid and O₂ in theO₂ rich stream to react with at least a portion of the hydrocarboncontaining material in the formation to generate synthesis gas having aselected ratio of H₂ to N₂; producing the synthesis gas from theformation; providing at least a portion of the H₂ and N₂ in thesynthesis gas to an ammonia synthesis process; and using the ammoniasynthesis process to generate ammonia.
 5079. The method of claim 5078,further comprising controlling a temperature of at least a portion ofthe selected section to generate synthesis gas having the selected H₂ toN₂ ratio.
 5080. The method of claim 5078, wherein the selected ratio isapproximately 3:1.
 5081. The method of claim 5078, wherein the selectedratio ranges from approximately 2.8:1 to approximately 3.2:1.
 5082. Themethod of claim 5078, wherein the temperature sufficient to supportreaction of hydrocarbon containing material in the formation to formsynthesis gas ranges from approximately 400° C. to approximately 1200°C.
 5083. The method of claim 5078, wherein the O₂ stream and N₂ streamare obtained by cryogenic separation of air.
 5084. The method of claim5078, wherein the O₂ stream and N₂ stream are obtained by membraneseparation of air.
 5085. The method of claim 5078, further comprisingseparating at least a portion of carbon dioxide in the synthesis gasfrom at least a portion of the synthesis gas.
 5086. The method of claim5085, wherein the carbon dioxide is separated from the synthesis gas byan amine separator.
 5087. The method of claim 5086, further comprisingproviding at least a portion of the carbon dioxide to a urea synthesisprocess.
 5088. The method of claim 5078, wherein fluids produced duringpyrolysis of an oil shale formation comprise ammonia and, furthercomprising adding at least a portion of such ammonia to the ammoniagenerated from the ammonia synthesis process.
 5089. The method of claim5078, wherein fluids produced during pyrolysis of a hydrocarbonformation are hydrotreated and at least some ammonia is produced duringhydrotreating, and further comprising adding at least a portion of suchammonia to the ammonia generated from the ammonia synthesis process.5090. The method of claim 5078, further comprising providing at least aportion of the ammonia to a urea synthesis process to produce urea.5091. The method of claim 5078, further comprising providing at least aportion of the ammonia to a urea synthesis process to produce urea and,further comprising providing carbon dioxide from the formation to theurea synthesis process.
 5092. The method of claim 5078, furthercomprising providing at least a portion of the ammonia to a ureasynthesis process to produce urea and further comprising shifting atleast a portion of carbon monoxide in the synthesis gas to carbondioxide in a shift process, and further comprising providing at least aportion of the carbon dioxide from the shift process to the ureasynthesis process.
 5093. The method of claim 5078, wherein heating aselected section of the formation to a temperature to support reactionof hydrocarbon containing material in the formation to form synthesisgas comprises: heating zones adjacent to wellbores of one or more heatsources with heaters disposed in the wellbores, wherein the heaters areconfigured to raise temperatures of the zones to temperatures sufficientto support reaction of hydrocarbon containing material within the zoneswith O₂ in the O₂ rich stream; introducing the O₂ to the zonessubstantially by diffusion; allowing O₂ in the O₂ rich stream to reactwith at least a portion of the hydrocarbon containing material withinthe zones to produce heat in the zones; and transferring heat from thezones to the selected section.
 5094. The method of claim 5093, whereintemperatures sufficient to support reaction of hydrocarbon containingmaterial within the zones with O₂ range from approximately 200° C. toapproximately 1200° C.
 5095. The method of claim 5093, wherein the oneor more heat sources comprises one or more electrical heaters disposedin the formation.
 5096. The method of claim 5093, wherein the one ormore heat sources comprises one or more natural distributed combustors.5097. The method of claim 5093, wherein the one or more heat sourcescomprise one or more heater wells, wherein at least one heater wellcomprises a conduit disposed within the formation, and furthercomprising heating the conduit by flowing a hot fluid through theconduit.
 5098. The method of claim 5093, further comprising using aportion of the synthesis gas as a combustion fuel for the one or moreheat sources.
 5099. The method of claim 5078, wherein heating theselected section of the formation to a temperature to support reactionof hydrocarbon containing material in the formation to form synthesisgas comprises: introducing the O₂ rich stream into the formation througha wellbore; transporting O₂ in the O₂ rich stream substantially byconvection into the portion of the selected section, wherein the portionof the selected section is at a temperature sufficient to support anoxidation reaction with O₂ in the O₂ rich stream; and reacting the O₂within the portion of the selected section to generate heat and raisethe temperature of the portion.
 5100. The method of claim 5099, whereinthe temperature sufficient to support an oxidation reaction with O₂ranges from approximately 200° C. to approximately 1200° C.
 5101. Themethod of claim 5099, wherein the one or more heat sources comprises oneor more electrical heaters disposed in the formation.
 5102. The methodof claim 5099, wherein the one or more heat sources comprises one ormore natural distributed combustors.
 5103. The method of claim 5099,wherein the one or more heat sources comprise one or more heater wells,wherein at least one heater well comprises a conduit disposed within theformation, and further comprising heating the conduit by flowing a hotfluid through the conduit.
 5104. The method of claim 5099, furthercomprising using a portion of the synthesis gas as a combustion fuel forthe one or more heat sources.
 5105. The method of claim 5078, furthercomprising controlling the heating of at least the portion of theselected section and provision of the synthesis gas generating fluid tomaintain a temperature within at least the portion of the selectedsection above the temperature sufficient to generate synthesis gas.5106. The method of claim 5078, wherein the synthesis gas generatingfluid comprises liquid water.
 5107. The method of claim 5078, whereinthe synthesis gas generating fluid comprises steam.
 5108. The method ofclaim 5078, wherein the synthesis gas generating fluid comprises waterand carbon dioxide, wherein the carbon dioxide inhibits production ofcarbon dioxide from the selected section.
 5109. The method of claim5108, wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.5110. The method of claim 5078, wherein the synthesis gas generatingfluid comprises carbon dioxide, and wherein a portion of the carbondioxide reacts with carbon in the formation to generate carbon monoxide.5111. The method of claim 5110, wherein a portion of the carbon dioxidewithin the synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 5112. The method of claim 5078, whereinproviding the synthesis gas generating fluid to at least the portion ofthe selected section comprises raising a water table of the formation toallow water to flow into the at least the portion of the selectedsection.
 5113. A method for producing ammonia using an oil shaleformation, comprising: providing a first stream comprising N₂ and carbondioxide to the formation; allowing at least a portion of the carbondioxide in the first stream to adsorb in the formation; producing asecond stream from the formation, wherein the second stream comprises alower percentage of carbon dioxide than the first stream; providing atleast a portion of the N₂ in the second stream to an ammonia synthesisprocess.
 5114. The method of claim 5113 wherein the second streamcomprises H₂ from the formation.
 5115. The method of claim 5113, whereinthe first stream is produced from an oil shale formation.
 5116. Themethod of claim 5115, wherein the first stream is generated by reactinga oxidizing fluid with hydrocarbon containing material in the formation.5117. The method of claim 5113, wherein the second stream comprises H₂from the formation and, further comprising providing such H₂ to theammonia synthesis process.
 5118. The method of claim 5113, furthercomprising using the ammonia synthesis process to generate ammonia.5119. The method of claim 5118, wherein fluids produced during pyrolysisof an oil shale formation comprise ammonia and, further comprisingadding at least a portion of such ammonia to the ammonia generated fromthe ammonia synthesis process.
 5120. The method of claim 5118, whereinfluids produced during pyrolysis of a hydrocarbon formation arehydrotreated and at least some ammonia is produced during hydrotreating,and further comprising adding at least a portion of such ammonia to theammonia generated from the ammonia synthesis process.
 5121. The methodof claim 5118, further comprising providing at least a portion of theammonia to a urea synthesis process to produce urea.
 5122. The method ofclaim 5118, further comprising providing at least a portion of theammonia to a urea synthesis process to produce urea and, furthercomprising providing carbon dioxide from the formation to the ureasynthesis process.
 5123. The method of claim 5118, further comprisingproviding at least a portion of the ammonia to a urea synthesis processto produce urea and further comprising shifting at least a portion ofcarbon monoxide in the synthesis gas to carbon dioxide in a shiftprocess, and further comprising providing at least a portion of thecarbon dioxide from the shift process to the urea synthesis process.5124. A method for treating hydrocarbons in at least a portion of an oilshale formation, wherein the portion has an average permeability of lessthan about 10 millidarcy, comprising: providing heat from three or moreheat sources to the formation; allowing the heat to transfer from threeor more of the heat sources to a selected section of the formation suchthat heat from the heat sources pyrolyzes at least some hydrocarbonswithin the selected section, and at least three of the heat sources arearranged in a substantially triangular pattern; and producing a mixturecomprising hydrocarbons from the formation.
 5125. The method of claim5124, wherein superposition of heat from at least the three heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 5126. The method of claim 5124, wherein the mixture isproduced from a production well located in a triangular region createdby at least three heat sources.
 5127. The method of claim 5124, furthercomprising allowing heat to transfer from at least one of the heatsources to the selected section to create thermal fractures in theformation, wherein the thermal fractures substantially increase thepermeability of the selected section.
 5128. The method of claim 5124,wherein the heat is provided such that an average temperature in theselected section ranges from approximately about 270° C. to about 375°C.
 5129. The method of claim 5124, wherein at least one of the heatsources comprises a electrical heater located in the formation. 5130.The method of claim 5124, wherein at least one of the heat sources islocated in a heater well, and wherein at least one of the heater wellscomprises a conduit located in the formation, and further comprisingheating the conduit by flowing a hot fluid through the conduit. 5131.The method of claim 5124, wherein at least some of the heat sources arearranged in a triangular pattern.
 5132. The method of claim 5124,further comprising: monitoring a composition of the produced mixture;and controlling a pressure in at least a portion of the formation tocontrol the composition of the produced mixture.
 5133. The method ofclaim 5132, wherein the pressure is controlled by a valve proximate to alocation where the mixture is produced.
 5134. The method of claim 5132,wherein the pressure is controlled such that pressure proximate to oneor more of the heat sources is greater than a pressure proximate to alocation where the fluid is produced.
 5135. The method of claim 5124,wherein an average distance between heat sources is between about 2 mand about 8 m.
 5136. A system configurable to heat an oil shaleformation, comprising: a conduit configurable to be placed within anopening in the formation; a conductor configurable to be placed withinthe conduit, wherein the conductor is further configurable to provideheat to at least a portion of the formation during use; at least onecentralizer configurable to be coupled to the conductor, wherein atleast one centralizer inhibits movement of the conductor within theconduit during use; and wherein the system is configurable to allow heatto transfer from the conductor to a section of the formation during use.5137. The system of claim 5136, wherein at least one centralizercomprises electrically-insulating material.
 5138. The system of claim5136, wherein at least one centralizer is configurable to inhibit arcingbetween the conductor and the conduit.
 5139. The system of claim 5136,wherein at least one centralizer comprises ceramic material.
 5140. Thesystem of claim 5136, wherein at least one centralizer comprises atleast one recess, wherein at least one recess is placed at a junction ofat least one centralizer and the first conductor, wherein at least oneprotrusion is formed on the first conductor at the junction to maintaina location of at least one centralizer on the first conductor, andwherein at least one protrusion resides substantially within at leastone recess.
 5141. The system of claim 5140, wherein at least oneprotrusion comprises a weld.
 5142. The system of claim 5140, wherein anelectrically-insulating material substantially covers at least onerecess.
 5143. The system of claim 5140, wherein a thermal plasma appliedcoating substantially covers at least one recess.
 5144. The system ofclaim 5140, wherein a thermal plasma applied coating comprises alumina.5145. The system of claim 5136, wherein the system is furtherconfigurable to allow at least some hydrocarbons to pyrolyze in theheated section of the formation during use.
 5146. The system of claim5136, further comprising an insulation layer configurable to be coupledto at least a portion of the conductor or at least one centralizer.5147. The system of claim 5136, wherein at least one centralizercomprises a neck portion.
 5148. The system of claim 5136, wherein atleast one centralizer comprises one or more grooves.
 5149. The system ofclaim 5136, wherein at least one centralizer comprises at least twoportions, and wherein the portions are configurable to be coupled to theconductor to form at least one centralizer placed on the conductor.5150. The system of claim 5136, wherein a thickness of the conductor isgreater adjacent to a lean zone in the formation than a thickness of theconductor adjacent to a rich zone in the formation such that more heatis provided to the rich zone.
 5151. The system of claim 5136, whereinthe system is configured to heat an oil shale formation, and wherein thesystem comprises: a conduit configured to be placed within an opening inthe formation; a conductor configured to be placed within the conduit,wherein the conductor is further configured to provide heat to at leasta portion of the formation during use; at least one centralizerconfigured to be coupled to the conductor, wherein at least onecentralizer inhibits movement of the conductor within the conduit duringuse; and wherein the system is configured to allow heat to transfer fromthe conductor to a section of the formation during use.
 5152. The systemof claim 5136, wherein the system heats an oil shale formation, andwherein the system comprises: a conduit placed within an opening in theformation; a conductor placed within the conduit, wherein the conductorprovides heat to at least a portion of the formation; at least onecentralizer coupled to the conductor, wherein at least one centralizerinhibits movement of the conductor within the conduit; and wherein thesystem allows heat to transfer from the conductor to a section of theformation.
 5153. The system of claim 5136, wherein the system isconfigurable to be removed from the opening in the formation.
 5154. Thesystem of claim 5136, further comprising a moveable thermocouple. 5155.The system of claim 5136, further comprising an isolation block.
 5156. Asystem configurable to heat an oil shale formation, comprising: aconduit configurable to be placed within an opening in the formation; aconductor configurable to be placed within the conduit, wherein theconductor is further configurable to provide heat to at least a portionof the formation during use; at least one centralizer configurable to becoupled to the conductor, wherein at least one centralizer inhibitsmovement of the conductor within the conduit during use wherein thesystem is configurable to allow heat to transfer from the conductor to asection of the formation during use; and wherein the system isconfigurable to be removed from the opening in the formation.
 5157. Anin situ method for heating an oil shale formation, comprising: applyingan electrical current to a conductor to provide heat to at least aportion of the formation, wherein the conductor is placed within aconduit, wherein at least one centralizer is coupled to the conductor toinhibit movement of the conductor within the conduit, and wherein theconduit is placed within an opening in the formation; and allowing theheat to transfer from the first conductor to a section of the formation.5158. The method of claim 5157, further comprising pyrolyzing at leastsome hydrocarbons in the section of the formation.
 5159. The method ofclaim 5157, further comprising inhibiting arcing between the conductorand the conduit.
 5160. A system configurable to heat an oil shaleformation, comprising: a conduit configurable to be placed within anopening in the formation; a conductor configurable to be placed within aconduit, wherein the conductor is further configurable to provide heatto at least a portion of the formation during use; an insulation layercoupled to at least a portion of the conductor, wherein the insulationlayer electrically insulates at least a portion of the conductor fromthe conduit during use; and wherein the system is configurable to allowheat to transfer from the conductor to a section of the formation duringuse
 5161. The system of claim 5160, wherein the insulation layercomprises a spiral insulation layer.
 5162. The system of claim 5160,wherein the insulation layer comprises at least one metal oxide. 5163.The system of claim 5160, wherein the insulation layer comprises atleast one alumina oxide.
 5164. The system of claim 5160, wherein theinsulation layer is configurable to be fastened to the conductor with ahigh temperature glue.
 5165. The system of claim 5160, wherein thesystem is further configurable to allow at least some hydrocarbons topyrolyze in the heated section of the formation during use.
 5166. Thesystem of claim 5160, wherein the system is configured to heat an oilshale formation, and wherein the system comprises: a conduit configuredto be placed within an opening in the formation; a conductor configuredto be placed within a conduit, wherein the conductor is furtherconfigured to provide heat to at least a portion of the formation duringuse; an insulation layer coupled to at least a portion of the conductor,wherein the insulation layer electrically insulates at least a portionof the conductor from the conduit during use; and wherein the system isconfigured to allow heat to transfer from the conductor to a section ofthe formation during use.
 5167. The system of claim 5160, wherein thesystem heats an oil shale formation, and wherein the system comprises: aconduit placed within an opening in the formation; a conductor placedwithin a conduit, wherein the conductor provides heat to at least aportion of the formation; an insulation layer coupled to at least aportion of the conductor, wherein the insulation layer electricallyinsulates at least a portion of the conductor from the conduit; andwherein the system allows heat to transfer from the conductor to asection of the formation.
 5168. An in situ method for heating an oilshale formation, comprising: applying an electrical current to aconductor to provide heat to at least a portion of the formation,wherein the conductor is placed within a conduit, wherein an insulationlayer is coupled to at least a portion of the conductor to electricallyinsulate at least a portion of the conductor from the conduit, andwherein the conduit is placed within an opening in the formation; andallowing the heat to transfer from the first conductor to a section ofthe formation.
 5169. The method of claim 5168, further comprisingpyrolyzing at least some hydrocarbons in the section of the formation.5170. The method of claim 5168, further comprising inhibiting arcingbetween the conductor and the conduit.
 5171. A method for making aconductor-in-conduit heat source for an oil shale formation, comprising:placing at least one protrusion on a conductor; placing at least onecentralizer on the conductor; and placing the conductor within a conduitto form a conductor-in-conduit heat source, wherein at least onecentralizer maintains a location of the conductor within the conduit.5172. The method of claim 5171, wherein at least one centralizercomprises at least two portions, and wherein the portions are coupled tothe conductor to form at least one centralizer placed on the conductor.5173. The method of claim 5171, further comprising placing theconductor-in-conduit heat source in an opening in an oil shaleformation.
 5174. The method of claim 5171, further comprising couplingan insulation layer on the conductor, wherein the insulation layer isconfigured to electrically insulate at least a portion of the conductorfrom the conduit.
 5175. The method of claim 5171, further comprisingproviding heat from the conductor-in-conduit heat source to at least aportion of the formation.
 5176. The method of claim 5171, furthercomprising pyrolyzing at least some hydrocarbons in a selected sectionof the formation.
 5177. The method of claim 5171, further comprisingproducing a mixture from a selected section of the formation.
 5178. Themethod of claim 5171, wherein the conductor-in-conduit heat source isconfigurable to provide heat to the oil shale formation.
 5179. Themethod of claim 5171, wherein at least one centralizer comprises atleast one recess placed at a junction of at least one centralizer on theconductor, and wherein at least one protrusion resides substantiallywithin at least one recess.
 5180. The method of claim 5179, furthercomprising at least partially covering at least one recess with anelectrically-insulating material.
 5181. The method of claim 5179,further comprising spraying an electrically-insulating material to atleast partially cover at least one recess.
 5182. The method of claim5171, wherein placing at least one protrusion on the conductor compriseswelding at least one protrusion on the conductor.
 5183. The method ofclaim 5171, further comprising coiling the conductor-in-conduit heatsource on a spool after forming the heat source.
 5184. The method ofclaim 5171, further comprising uncoiling the heat source from the spoolwhile placing the heat source in an opening in the formation.
 5185. Themethod of claim 5171, wherein placing the conductor within a conduitcomprises placing the conductor within a conduit that has been placed inan opening in the formation.
 5186. The method of claim 5171, furthercomprising coupling the conductor-in-conduit heat source to at least oneadditional conductor-in-conduit heat source.
 5187. The method of claim5171, wherein the conductor-in-conduit heat source is configurable to beinstalled into an opening in an oil shale formation.
 5188. The method ofclaim 5171, wherein the conductor-in-conduit heat source is configurableto be removed from an opening in an oil shale formation.
 5189. Themethod of claim 5171, wherein the conductor-in-conduit heat source isconfigurable to heat to a section of the oil shale formation, andwherein the heat pyrolyzes at least some hydrocarbons in the section ofthe formation during use.
 5190. The method of claim 5171, wherein athickness of the conductor configurable to be placed adjacent to a leanzone in the formation is greater than a thickness of the conductorconfigurable to be placed adjacent to a rich zone in the formation suchthat more heat is provided to the rich zone during use.
 5191. A methodfor forming an opening in an oil shale formation, comprising: forming afirst opening in the formation; providing a series of magnetic fieldsfrom a plurality of magnets positioned along a portion of the firstopening; and forming a second opening in the formation using magnetictracking such that the second opening is positioned a selected distancefrom the first opening.
 5192. The method of claim 5191, furthercomprising providing a magnetic string to a portion of the firstopening.
 5193. The method of claim 5191, wherein the plurality ofmagnets is positioned within a casing.
 5194. The method of claim 5191,wherein the plurality of magnets is positioned within a heater casing.5195. The method of claim 5191, wherein the plurality of magnets ispositioned within a perforated casing.
 5196. The method of claim 5191,further comprising providing a magnetic string to a portion of the firstopening, wherein the magnetic string comprises two or more magneticsegments, and wherein the two or more segments are positioned such thatthe polarity of adjacent segments is reversed.
 5197. The method of claim5191, further comprising moving the magnetic fields within the firstopening.
 5198. The method of claim 5191, further comprising moving themagnetic fields within the first opening such that the magnetic fieldsvary with time.
 5199. The method of claim 5191, further comprisingadjusting a position of the magnetic fields within the first opening toincrease a length of the second opening.
 5200. The method of claim 5191,further comprising forming a plurality of openings adjacent to the firstopening.
 5201. The method of claim 5191, wherein the first openingcomprises a non-metallic casing.
 5202. The method of claim 5191, whereinthe series of the magnetic fields comprises a first magnetic field and asecond magnetic field and wherein a strength of the first magneticdiffers from a strength of the second magnetic field.
 5203. The methodof claim 5191, wherein the series of the magnetic fields comprises afirst magnetic field and a second magnetic field and wherein a strengthof the first magnetic is about a strength of the second magnetic field.5204. The method of claim 5191, wherein the first opening comprises acenter opening in a pattern of openings, and further comprising forminga plurality of openings adjacent to the first opening.
 5205. The methodof claim 5191, wherein the first opening comprises a center opening in apattern of openings, and further comprising forming a plurality ofopenings adjacent to the first opening, wherein each of the plurality ofopenings is positioned at the selected distance from the first opening.5206. The method of claim 5191, further comprising providing at leastone heating mechanism within the first opening and at least one heatingmechanism within the second opening such that the heating mechanisms canprovide heat to at least a portion of the formation.
 5207. A method forforming an opening in an oil shale formation, comprising: forming afirst opening in the formation; providing a magnetic string to the firstopening, wherein the magnetic string comprises two or more magneticsegments, and wherein the magnetic segments are positioned such that thepolarities of the segments are reversed; and forming a second opening inthe formation using magnetic tracking such that the second opening ispositioned a selected distance from the first opening.
 5208. The methodof claim 5207, further comprising providing at least one heatingmechanism within the first opening and at least one heating mechanismwithin the second opening such that the heating mechanisms can provideheat to at least a portion of the formation.
 5209. The method of claim5207, wherein the two or more segments comprise a plurality of magnets.5210. The method of claim 5207, further comprising providing a series ofmagnetic fields along a portion of the first opening.
 5211. The methodof claim 5207, wherein a length of a segment corresponds to a distancebetween the first opening and the second opening.
 5212. The method ofclaim 5207, further comprising moving the magnetic fields within thefirst opening.
 5213. The method of claim 5207, further comprising movingthe magnetic fields within the first opening such that the magneticfields vary with time.
 5214. The method of claim 5207, furthercomprising adjusting a position of the magnetic fields within the firstopening to increase a length of the second opening.
 5215. The method ofclaim 5207, further comprising forming a plurality of openings adjacentto the first opening.
 5216. The method of claim 5207, wherein the firstopening comprises a non-metallic casing.
 5217. The method of claim 5207,wherein the series of the magnetic fields comprises a first magneticfield and a second magnetic field and wherein a strength of the firstmagnetic field differs from a strength of the second magnetic field.5218. The method of claim 5207, wherein the series of the magneticfields comprises a first magnetic field and a second magnetic field andwherein a strength of the first magnetic field is about a strength ofthe second magnetic field.
 5219. The method of claim 5207, wherein thefirst opening comprises a center opening in a pattern of openings, andfurther comprising forming a plurality of openings adjacent to the firstopening.
 5220. The method of claim 5207, wherein the first openingcomprises a center opening in a pattern of openings, and furthercomprising forming a plurality of openings adjacent to the firstopening, wherein each of the plurality of openings is positioned at theselected distance from the first opening.
 5221. The method of claim5207, further comprising providing at least one heating mechanism withinthe first opening and at least one heating mechanism within the secondopening such that the heating mechanisms can provide heat to at least aportion of the formation.
 5222. The method of claim 5207, wherein themagnetic string is positioned within a casing.
 5223. The method of claim5207, wherein the magnetic string is positioned within a heater casing.5224. A system for drilling openings in an oil shale formation,comprising: a drilling apparatus; a magnetic string, comprising: aconduit; and two or more magnetic segments positionable in the conduit,wherein the magnetic segments comprise a plurality of magnets ; and asensor configurable to detect a magnetic field within the formation.5225. The system of claim 5224, wherein the magnetic string furthercomprises one or more members configurable to inhibit movement of themagnetic segments relative to the conduit.
 5226. The system of claim5224, wherein the one or more magnetic segments are positioned such thata polarity of adjacent segments is reversed.
 5227. The system of claim5224, wherein the magnetic string is positionable within a first openingin the formation.
 5228. The system of claim 5224, wherein the magneticstring is positionable within a first opening in the formation andwherein the magnetic string induces a magnetic field in a portion of thefirst opening.
 5229. The system of claim 5224, further comprising atleast one heating mechanism within a first opening.
 5230. The system ofclaim 5224, further comprising at least one heating mechanism within afirst opening and at least one heating mechanism within a second openingsuch that the heating mechanisms can provide heat to at least a portionof the formation.
 5231. The system of claim 5224, further comprisingproviding a series of magnetic fields along a portion of a firstopening.
 5232. The system of claim 5224, wherein a length of a segmentcorresponds to a distance between the first opening and the secondopening.
 5233. The system of claim 5224, wherein the magnetic string ismovable in a first opening.
 5234. The system of claim 5224, wherein aposition of the magnetic string in the first opening can be adjusted toincrease a length of a second opening.
 5235. The system of claim 5224,further comprising a first opening positioned in the formation andwherein the magnetic string is positionable in the first opening. 5236.The system of claim 5224, further comprising a non-metallic casing.5237. The system of claim 5224, wherein the magnetic segments comprisesa first magnetic segment and a second magnetic segment and wherein alength of the first magnetic segment differs from a length of the secondmagnetic segment.
 5238. The system of claim 5224, wherein the magneticsegments comprises a first magnetic segment and a second magneticsegment and wherein a length of the first magnetic segment is about thesame as a length of the second magnetic segment.
 5239. The system ofclaim 5224, further comprising a casing and wherein the magnetic stringis positioned within the casing.
 5240. A method of installing aconductor-in-conduit heat source of a desired length in an oil shaleformation, comprising: assembling a conductor-in-conduit heat source ofa desired length, comprising: placing a conductor within a conduit toform a conductor-in-conduit heat source; and coupling theconductor-in-conduit heat source to at least one additionalconductor-in-conduit heat source to form a conductor-in-conduit heatsource of the desired length, wherein the conductor is electricallycoupled to the conductor of at least one additional conductor-in-conduitheat source and the conduit is electrically coupled to the conduit of atleast one additional conductor-in-conduit heat source; coiling theconductor-in-conduit heat source of the desired length after forming theheat source; and placing the conductor-in-conduit heat source of thedesired length in an opening in an oil shale formation.
 5241. The methodof claim 5240, wherein the conductor-in-conduit heat source isconfigurable to provide heat to the oil shale formation.
 5242. Themethod of claim 5240, wherein the conductor-in-conduit heat source ofthe desired length is removable from the opening in the oil shaleformation.
 5243. The method of claim 5240, further comprising uncoilingthe conductor-in-conduit heat source of the desired length while placingthe heat source in the opening.
 5244. The method of claim 5240, furthercomprising placing at least one centralizer on the conductor.
 5245. Themethod of claim 5240, further comprising placing at least onecentralizer on the conductor, wherein at least one centralizer inhibitsmovement of the conductor within the conduit.
 5246. The method of claim5240, further comprising placing an insulation layer on at least aportion of the conductor.
 5247. The method of claim 5240, furthercomprising coiling the conductor-in-conduit heat source.
 5248. Themethod of claim 5240, further comprising testing theconductor-in-conduit heat source and coiling the heat source.
 5249. Themethod of claim 5240, wherein coupling the conductor-in-conduit heatsource to at least one additional conductor-in-conduit heat sourcecomprises welding the conductor-in-conduit heat source to at least oneadditional conductor-in-conduit heat source.
 5250. The method of claim5240, wherein coupling the conductor-in-conduit heat source to at leastone additional conductor-in-conduit heat source comprises shieldedactive gas welding the conductor-in-conduit heat source to at least oneadditional conductor-in-conduit heat source.
 5251. The method of claim5240, wherein coupling the conductor-in-conduit heat source to at leastone additional conductor-in-conduit heat source comprises shieldedactive gas welding the conductor-in-conduit heat source to at least oneadditional conductor-in-conduit heat source, and wherein using shieldedactive gas welding inhibits changes in the grain structure of theconductor or conduit during coupling.
 5252. The method of claim 5240,wherein the assembling of the conductor-in-conduit heat source of thedesired length is performed at a location proximate the oil shaleformation.
 5253. The method of claim 5240, wherein the assembling of theconductor-in-conduit heat source of the desired length takes placesufficiently proximate the oil shale formation such that theconductor-in-conduit heat source can be placed directly in an opening ofthe formation after the heat source is assembled.
 5254. The method ofclaim 5240, further comprising coupling at least one substantially lowresistance conductor to the conductor-in-conduit heat source of thedesired length, wherein at least one substantially low resistanceconductor is configured to be placed in an overburden of the formation.5255. The method of claim 5254, further comprising coupling at least oneadditional substantially low resistance conductor to at least onesubstantially low resistance conductor.
 5256. The method of claim 5254,further comprising coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor, wherein coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor comprises coupling a threaded end of at least one additionalsubstantially low resistance conductor to a threaded end of at least onesubstantially low resistance conductor.
 5257. The method of claim 5254,further comprising coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor, wherein coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor comprises welding at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor.
 5258. The method of claim 5254, wherein at least onesubstantially low resistance conductor is coupled to theconductor-in-conduit heat source of the desired length during assemblingof the heat source of the desired length.
 5259. The method of claim5254, wherein at least one substantially low resistance conductor iscoupled to the conductor-in-conduit heat source of the desired lengthafter assembling of the heat source of the desired length.
 5260. Themethod of claim 5240, further comprising transporting the coiledconductor-in-conduit heat source of the desired length on a cart ortrain from an assembly location to the opening in the oil shaleformation.
 5261. The method of claim 5260, wherein the cart or train canbe further used to transport more than one conductor-in-conduit heatsource of the desired length to more than one opening in the oil shaleformation.
 5262. The method of claim 5240, wherein the desired lengthcomprises a length determined for using the conductor-in-conduit heatsource in a selected opening in the oil shale formation.
 5263. Themethod of claim 5240, further comprising treating the conductor toincrease an emissivity of the conductor.
 5264. The method of claim 5263,wherein treating the conductor comprises roughening the surface of theconductor.
 5265. The method of claim 5263, wherein treating theconductor comprises heating the conductor to a temperature above about750° C. in an oxidizing fluid atmosphere.
 5266. The method of claim5240, further comprising treating the conduit to increase an emissivityof the conduit.
 5267. The method of claim 5240, further comprisingcoating at least a portion of the conductor or at least a portion of theconduit during assembly of the conductor-in-conduit heat source. 5268.The method of claim 5240, further comprising placing an insulation layeron at least a portion of the conductor-in-conduit heat source prior toplacing the heat source in the opening in the oil shale formation. 5269.The method of claim 5268, wherein the insulation layer comprises aspiral insulation layer.
 5270. The method of claim 5268, wherein theinsulation layer comprises at least one metal oxide.
 5271. The method ofclaim 5268, further comprising fastening at least a portion of theinsulation layer to at least a portion of the conductor-in-conduit heatsource with a high temperature glue.
 5272. The method of claim 5240,further comprising providing heat from the conductor-in-conduit heatsource of the desired length to at least a portion of the formation.5273. The method of claim 5240, wherein a thickness of the conductorconfigurable to be placed adjacent to a lean zone in the formation isgreater than a thickness of the conductor configurable to be placedadjacent to a rich zone in the formation such that more heat is providedto the rich zone during use
 5274. The method of claim 5240, furthercomprising pyrolyzing at least some hydrocarbons in a selected sectionof the formation.
 5275. The method of claim 5240, further comprisingproducing a mixture from a selected section of the formation.
 5276. Amethod for making a conductor-in-conduit heat source configurable to beused to heat an oil shale formation, comprising: placing a conductorwithin a conduit to form a conductor-in-conduit heat source; andshielded active gas welding the conductor-in-conduit heat source to atleast one additional conductor-in-conduit heat source to form aconductor-in-conduit heat source of a desired length, wherein theconductor is electrically coupled to the conductor of at least oneadditional conductor-in-conduit heat source and the conduit iselectrically coupled to the conduit of at least one additionalconductor-in-conduit heat source; and wherein the conductor-in-conduitheat source is configurable to be placed in an opening in the oil shaleformation, and wherein the conductor-in-conduit heat source is furtherconfigurable to heat a section of the oil shale formation during use.5277. The method of claim 5276, further comprising providing heat fromthe conductor-in-conduit heat source of the desired length to at least aportion of the formation.
 5278. The method of claim 5276, furthercomprising pyrolyzing at least some hydrocarbons in a selected sectionof the formation.
 5279. The method of claim 5276, further comprisingproducing a mixture from a selected section of the formation.
 5280. Themethod of claim 5276, wherein the conductor and the conduit comprisestainless steel.
 5281. The method of claim 5276, wherein the conduitcomprises stainless steel.
 5282. The method of claim 5276, wherein theheat source is configurable to be removed from the formation.
 5283. Themethod of claim 5276, further comprising providing a reducing gas duringwelding.
 5284. The method of claim 5276, wherein the reducing gascomprises molecular hydrogen.
 5285. The method of claim 5276, furthercomprising providing a reducing gas during welding such that weldingoccurs in an environment comprising less than about 25% reducing gas byvolume.
 5286. The method of claim 5276, further comprising providing areducing gas during welding such that welding occurs in an environmentcomprising about 10% reducing gas by volume.
 5287. A system configurableto heat an oil shale formation, comprising: a conduit configurable to beplaced within an opening in the formation; a conductor configurable tobe placed within the conduit, wherein the conductor is furtherconfigurable to provide heat to at least a portion of the formationduring use, and wherein the conductor comprises at least two conductorsections coupled by shielded active gas welding; and wherein the systemis configurable to allow heat to transfer from the conductor to asection of the formation during use.
 5288. The system of claim 5287,wherein the conduit comprises at least two conduit sections coupled byshielded active gas welding.
 5289. The system of claim 5287, wherein thesystem is further configurable to allow at least some hydrocarbons topyrolyze in the heated section of the formation during use.
 5290. Thesystem of claim 5287, wherein the system is configured to heat an oilshale formation, and wherein the system comprises: a conduit configuredto be placed within an opening in the formation; a conductor configuredto be placed within the conduit, wherein the conductor is furtherconfigured to provide heat to at least a portion of the formation duringuse, and wherein the conductor comprises at least two conductor sectionscoupled by shielded active gas welding; and wherein the system isconfigured to allow heat to transfer from the conductor to a section ofthe formation during use.
 5291. The system of claim 5287, wherein thesystem heats an oil shale formation, and wherein the system comprises: aconduit placed within an opening in the formation; a conductor placedwithin the conduit, wherein the conductor provides heat to at least aportion of the formation during use, and wherein the conductor comprisesat least two conductor sections coupled by shielded active gas welding;and wherein the system allows heat to transfer from the conductor to asection of the formation during use.
 5292. The system of claim 5287,wherein the conductor-in-conduit heat source is configurable to beremoved from the formation.
 5293. A method for installing a heat sourceof a desired length in an oil shale formation, comprising: assembling aheat source of a desired length, wherein the assembling of the heatsource of the desired length is performed at a location proximate theoil shale formation; coiling the heat source of the desired length afterforming the heat source; and placing the heat source of the desiredlength in an opening in an oil shale formation, wherein placing the heatsource in the opening comprises uncoiling the heat source while placingthe heat source in the opening.
 5294. The method of claim 5293, whereinthe heat source is configurable to heat a section of the oil shaleformation.
 5295. The method of claim 5294, wherein the heat pyrolyzes atleast some hydrocarbons in the section of the formation during use.5296. The method of claim 5293, further comprising coupling at least onesubstantially low resistance conductor to the heat source of the desiredlength, wherein at least one substantially low resistance conductor isconfigured to be placed in an overburden of the formation.
 5297. Themethod of claim 5296, further comprising coupling at least oneadditional substantially low resistance conductor to at least onesubstantially low resistance conductor.
 5298. The method of claim 5296,further comprising coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor, wherein coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor comprises coupling a threaded end of at least one additionalsubstantially low resistance conductor to a threaded end of at least onesubstantially low resistance conductor.
 5299. The method of claim 5296,further comprising coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor, wherein coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor comprises welding at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor.
 5300. The method of claim 5293, further comprisingtransporting the heat source of the desired length on a cart or trainfrom an assembly location to the opening in the oil shale formation.5301. The method of claim 5300, wherein the cart or train can be furtherused to transport more than one heat source to more than one opening inthe oil shale formation.
 5302. The method of claim 5300, wherein theheat source is configurable to removable from the opening.
 5303. Amethod for installing a heat source of a desired length in an oil shaleformation, comprising: assembling a heat source of a desired length,wherein the assembling of the heat source of the desired length isperformed at a location proximate the oil shale formation; coiling theheat source of the desired length after forming the heat source; placingthe heat source of the desired length in an opening in an oil shaleformation, wherein placing the heat source in the opening comprisesuncoiling the heat source while placing the heat source in the opening;and wherein the heat source is configurable to be removed from theopening.
 5304. The method of claim 5303, wherein the heat source isconfigurable to heat a section of the oil shale formation.
 5305. Themethod of claim 5304, wherein the heat pyrolyzes at least somehydrocarbons in the section of the formation during use.
 5306. Themethod of claim 5303, further comprising coupling at least onesubstantially low resistance conductor to the heat source of the desiredlength, wherein at least one substantially low resistance conductor isconfigured to be placed in an overburden of the formation.
 5307. Themethod of claim 5306, further comprising coupling at least oneadditional substantially low resistance conductor to at least onesubstantially low resistance conductor.
 5308. The method of claim 5306,further comprising coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor, wherein coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor comprises coupling a threaded end of at least one additionalsubstantially low resistance conductor to a threaded end of at least onesubstantially low resistance conductor.
 5309. The method of claim 5306,further comprising coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor, wherein coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor comprises welding at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor.
 5310. The method of claim 5303, further comprisingtransporting the heat source of the desired length on a cart or trainfrom an assembly location to the opening in the oil shale formation.5311. The method of claim 5303, wherein removing the heat sourcecomprises recoiling the heat source.
 5312. The method of claim 5303,wherein the heat source can be removed from the opening and installed inan alternate opening in the formation.
 5313. A system configurable toheat an oil shale formation, comprising: a conduit configurable to beplaced within an opening in the formation; a conductor configurable tobe placed within a conduit, wherein the conductor is furtherconfigurable to provide heat to at least a portion of the formationduring use; an electrically conductive material configurable to becoupled to at least a portion of the conductor, wherein the electricallyconductive material is configurable to lower an electrical resistance ofthe conductor in the overburden during use; and wherein the system isconfigurable to allow heat to transfer from the conductor to a sectionof the formation during use.
 5314. The system of claim 5313, furthercomprising an electrically conductive material configurable to becoupled to at least a portion of an inside surface of the conduit. 5315.The system of claim 5313, further comprising a substantially lowresistance conductor configurable to be electrically coupled to theconductor and the electrically conductive material during use, whereinthe substantially low resistance conductor is further configurable to beplaced within an overburden of the formation.
 5316. The system of claim5315, wherein the low resistance conductor comprises carbon steel. 5317.The system of claim 5313, wherein the electrically conductive materialcomprises metal tubing configurable to be clad to the conductor. 5318.The system of claim 5313, wherein the electrically conductive materialcomprises an electrically conductive coating configurable to be appliedto the conductor.
 5319. The system of claim 5313, wherein theelectrically conductive material comprises a thermal plasma appliedcoating.
 5320. The system of claim 5313, wherein the electricallyconductive material is configurable to be sprayed on the conductor.5321. The system of claim 5313, wherein the electrically conductivematerial comprises aluminum.
 5322. The system of claim 5313, wherein theelectrically conductive material comprises copper.
 5323. The system ofclaim 5313, wherein the electrically conductive material is configurableto reduce the electrical resistance of the conductor in the overburdenby a factor of greater than about
 3. 5324. The system of claim 5313,wherein the electrically conductive material is configurable to reducethe electrical resistance of the conductor in the overburden by a factorof greater than about
 15. 5325. The system of claim 5313, wherein thesystem is further configurable to allow at least some hydrocarbons topyrolyze in the heated section of the formation during use.
 5326. Thesystem of claim 5313, wherein the system is configured to heat an oilshale formation, and wherein the system comprises: a conduit configuredto be placed within an opening in the formation; a conductor configuredto be placed within a conduit, wherein the conductor is furtherconfigured to provide heat to at least a portion of the formation duringuse; an electrically conductive material configured to be coupled to theconductor, wherein the electrically conductive material is furtherconfigured to lower an electrical resistance of the conductor in theoverburden during use; and wherein the system is configured to allowheat to transfer from the conductor to a section of the formation duringuse.
 5327. The system of claim 5313, wherein the system heats an oilshale formation, and wherein the system comprises: a conduit placedwithin an opening in the formation; a conductor placed within a conduit,wherein the conductor is provides heat to at least a portion of theformation during use; an electrically conductive material coupled to theconductor, wherein the electrically conductive material lowers anelectrical resistance of the conductor in the overburden during use; andwherein the system allows heat to transfer from the conductor to asection of the formation during use.
 5328. An in situ method for heatingan oil shale formation, comprising: applying an electrical current to aconductor to provide heat to at least a portion of the formation,wherein the conductor is placed in a conduit, and wherein the conduit isplaced in an opening in the formation, and wherein the conductor iscoupled to an electrically conductive material; and allowing the heat totransfer from the conductor to a section of the formation.
 5329. Themethod of claim 5328, wherein the electrically conductive materialcomprises copper.
 5330. The method of claim 5328, further comprisingcoupling an electrically conductive material to an inside surface of theconduit.
 5331. The method of claim 5328, wherein the electricallyconductive material comprises metal tubing clad to the substantially lowresistance conductor.
 5332. The method of claim 5328, wherein theelectrically conductive material reduces an electrical resistance of thesubstantially low resistance conductor in the overburden.
 5333. Themethod of claim 5328, further comprising pyrolyzing at least somehydrocarbons within the formation.
 5334. A system configurable to heatan oil shale formation, comprising: a conduit configurable to be placedwithin an opening in the formation; a conductor configurable to beplaced within a conduit, wherein the conductor is further configurableto provide heat to at least a portion of the formation during use, andwherein the conductor has been treated to increase an emissivity of atleast a portion of a surface of the conductor; and wherein the system isconfigurable to allow heat to transfer from the conductor to a sectionof the formation during use.
 5335. The system of claim 5334, wherein atleast a portion of the surface of the conductor has been roughened toincrease the emissivity of the conductor.
 5336. The system of claim5334, wherein the conductor has been heated to a temperature above about750° C. in an oxidizing fluid atmosphere to increase the emissivity ofat least a portion of the surface of the conductor.
 5337. The system ofclaim 5334, wherein the conduit has been treated to increase anemissivity of at least a portion of the surface of the conduit. 5338.The system of claim 5334, further comprising an electrically insulative,thermally conductive coating coupled to the conductor.
 5339. The systemof claim 5338, wherein the electrically insulative, thermally conductivecoating is configurable to electrically insulate the conductor from theconduit.
 5340. The system of claim 5338, wherein the electricallyinsulative, thermally conductive coating inhibits emissivity of theconductor from decreasing.
 5341. The system of claim 5338, wherein theelectrically insulative, thermally conductive coating substantiallyincreases an emissivity of the conductor.
 5342. The system of claim5338, wherein the electrically insulative, thermally conductive coatingcomprises silicon oxide.
 5343. The system of claim 5338, wherein theelectrically insulative, thermally conductive coating comprises aluminumoxide.
 5344. The system of claim 5338, wherein the electricallyinsulative, thermally conductive coating comprises refractive cement.5345. The system of claim 5338, wherein the electrically insulative,thermally conductive coating is sprayed on the conductor.
 5346. Thesystem of claim 5334, wherein the system is further configurable toallow at least some hydrocarbons to pyrolyze in the heated section ofthe formation during use.
 5347. The system of claim 5334, wherein thesystem is configured to heat an oil shale formation, and wherein thesystem comprises: a conduit configured to be placed within an opening inthe formation; a conductor configured to be placed within a conduit,wherein the conductor is further configured to provide heat to at leasta portion of the formation during use, and wherein the conductor hasbeen treated to increase an emissivity of at least a portion of asurface of the conductor; and wherein the system is configured to allowheat to transfer from the conductor to a section of the formation duringuse.
 5348. The system of claim 5334, wherein the system heats an oilshale formation, and wherein the system comprises: a conduit placedwithin an opening in the formation; a conductor placed within a conduit,wherein the conductor provides heat to at least a portion of theformation during use, and wherein the conductor has been treated toincrease an emissivity of at least a portion of a surface of theconductor; and wherein the system allows heat to transfer from theconductor to a section of the formation during use.
 5349. A heat sourceconfigurable to heat an oil shale formation, comprising: a conduitconfigurable to be placed within an opening in the formation; and aconductor configurable to be placed within a conduit, wherein theconductor is further configurable to provide heat to at least a portionof the formation during use, and wherein the conductor has been treatedto increase an emissivity of at least a portion of a surface of theconductor.
 5350. The heat source of claim 5349, wherein at least aportion of the surface of the conductor has been roughened to increasethe emissivity the conductor.
 5351. The heat source of claim 5349,wherein the conductor has been heated to a temperature above about 750°C. in an oxidizing fluid atmosphere to increase the emissivity of atleast at least a portion of the surface of the conductor.
 5352. The heatsource of claim 5349, wherein the conduit has been treated to increasean emissivity of at least a portion of the surface of the conduit. 5353.The heat source of claim 5349, further comprising an electricallyinsulative, thermally conductive coating placed on the conductor. 5354.The heat source of claim 5353, wherein the electrically insulative,thermally conductive coating is configurable to electrically insulatethe conductor from the conduit.
 5355. The heat source of claim 5353,wherein the electrically insulative, thermally conductive coatingsubstantially maintains an emissivity of the conductor.
 5356. The heatsource of claim 5353, wherein the electrically insulative, thermallyconductive coating substantially increases an emissivity of theconductor.
 5357. The heat source of claim 5353, wherein the electricallyinsulative, thermally conductive coating comprises silicon oxide. 5358.The heat source of claim 5353, wherein the electrically insulative,thermally conductive coating comprises aluminum oxide.
 5359. The heatsource of claim 5353, wherein the electrically insulative, thermallyconductive coating comprises refractive cement.
 5360. The heat source ofclaim 5353, wherein the electrically insulative, thermally conductivecoating is sprayed on the conductor.
 5361. The heat source of claim5349, wherein the conductor is further configurable to provide heat toat least a portion of the formation during use such that at least somehydrocarbons pyrolyze in the heated section of the formation during use.5362. The heat source of claim 5349, wherein the heat source isconfigured to heat an oil shale formation, and wherein the systemcomprises: a conduit configured to be placed within an opening in theformation; a conductor configured to be placed within a conduit, whereinthe conductor is further configured to provide heat to at least aportion of the formation during use, and wherein the conductor has beentreated to increase an emissivity of at least a portion of a surface ofthe conductor.
 5363. The heat source of claim 5349, wherein the heatsource heats an oil shale formation, and wherein the system comprises: aconduit placed within an opening in the formation; a conductor placedwithin a conduit, wherein the conductor provides heat to at least aportion of the formation, and wherein the conductor has been treated toincrease an emissivity of at least a portion of a surface of theconductor.
 5364. A method for forming an increased emissivityconductor-in-conduit heat source, comprising: treating a surface of aconductor to increase an emissivity of at least the surface of theconductor; placing the conductor within a conduit to form aconductor-in-conduit heat source; and wherein the conductor-in-conduitheat source is configurable to heat an oil shale formation.
 5365. Themethod of claim 5364, wherein treating the surface of the conductorcomprises roughening at least a portion of the surface of the conductor.5366. The method of claim 5364, wherein treating the surface of theconductor comprises heating the conductor to a temperature above about750° C. in an oxidizing fluid atmosphere.
 5367. The method of claim5364, further comprising treating a surface of the conduit to increasean emissivity of at least a portion of the surface of the conduit. 5368.The method of claim 5364, further comprising placing theconductor-in-conduit heat source of the desired length in an opening inan oil shale formation.
 5369. The method of claim 5364, furthercomprising assembling a conductor-in-conduit heat source of a desiredlength, the assembling comprising: coupling the conductor-in-conduitheat source to at least one additional conductor-in-conduit heat sourceto form a conductor-in-conduit heat source of a desired length, whereinthe conductor is electrically coupled to the conductor of at least oneadditional conductor-in-conduit heat source and the conduit iselectrically coupled to the conduit of at least one additionalconductor-in-conduit heat source; coiling the conductor-in-conduit heatsource of the desired length after forming the heat source; and placingthe conductor-in-conduit heat source of the desired length in an openingin an oil shale formation.
 5370. The method of claim 5364, wherein theconductor-in-conduit heat source is configurable to heat to a section ofthe oil shale formation, and wherein the heat pyrolyzes at least somehydrocarbons in the section of the formation during use.
 5371. A systemconfigurable to heat an oil shale formation, comprising: a heat sourceconfigurable to be placed in an opening in the formation, wherein theheat source is further configurable to provide heat to at least aportion of the formation during use; an expansion mechanism configurableto be coupled to the heat source, wherein the expansion mechanism isconfigurable to allow for movement of the heat source during use; andwherein the system is configurable to allow heat to transfer to asection of the formation during use.
 5372. The system of claim 5371,wherein the expansion mechanism is configurable to allow for expansionof the heat source during use.
 5373. The system of claim 5371, whereinthe expansion mechanism is configurable to allow for contraction of theheat source during use.
 5374. The system of claim 5371, wherein theexpansion mechanism is configurable to allow for expansion of at leastone component of the heat source during use.
 5375. The system of claim5371, wherein the expansion mechanism is configurable to allow forexpansion and contraction of the heat source within a wellbore duringuse.
 5376. The system of claim 5371, wherein the expansion mechanismcomprises spring loading.
 5377. The system of claim 5371, wherein theexpansion mechanism comprises an accordion mechanism.
 5378. The systemof claim 5371, wherein the expansion mechanism is configurable to becoupled to a bottom of the heat source.
 5379. The system of claim 5371,wherein the heat source is configurable to allow at least somehydrocarbons to pyrolyze in the heated section of the formation duringuse.
 5380. The system of claim 5371, wherein the system is configured toheat an oil shale formation, and wherein the system comprises: a heatsource configured to be placed in an opening in the formation, whereinthe heat source is further configured to provide heat to at least aportion of the formation during use; an expansion mechanism configuredto be coupled to the heat source, wherein the expansion mechanism isconfigured to allow for movement of the heat source during use; andwherein the system is configured to allow heat to transfer to a sectionof the formation during use.
 5381. The system of claim 5371, wherein thesystem heats an oil shale formation, and wherein the system comprises: aheat source placed in an opening in the formation, wherein the heatsource provides heat to at least a portion of the formation during use;an expansion mechanism coupled to the heat source, wherein the expansionmechanism allows for movement of the heat source during use; and whereinthe system allows heat to transfer to a section of the formation duringuse.
 5382. The system of claim 5371, wherein the heat source isremovable.
 5383. A system configurable to provide heat to an oil shaleformation, comprising: a conduit positionable in at least a portion ofan opening in the formation, wherein a first end of the opening contactsan earth surface at a first location, and wherein a second end of theopening contacts the earth surface at a second location; and an oxidizerconfigurable to provide heat to a selected section of the formation bytransferring heat through the conduit.
 5384. The system of claim 5383,wherein heat from the oxidizer pyrolyzes at least some hydrocarbons inthe selected section.
 5385. The system of claim 5383, wherein theconduit is positioned in the opening.
 5386. The system of claim 5383,where in the oxidizer is positionable in the conduit.
 5387. The systemof claim 5383, wherein the oxidizer is positioned in the conduit, andwherein the oxidizer is configured to heat the selected section. 5388.The system of claim 5383, wherein the oxidizer comprises a ring burner.5389. The system of claim 5383, wherein the oxidizer comprises an inlineburner.
 5390. The system of claim 5383, wherein the oxidizer isconfigurable to provide heat in the conduit.
 5391. The system of claim5383, further comprising an annulus formed between a wall of the conduitand a wall of the opening.
 5392. The system of claim 5383, wherein theoxidizer comprises a first oxidizer and a second oxidizer, and furthercomprising an annulus formed between a wall of the conduit and a wall ofthe opening, wherein the second oxidizer is positionable in the annulus.5393. The system of claim 5392, wherein the first oxidizer isconfigurable to provide heat in the conduit, and wherein the secondoxidizer is configurable to provide heat outside of the conduit. 5394.The system of claim 5392, wherein heat provided by the first oxidizertransfers in the first conduit in a direction opposite of heat providedby the second oxidizer.
 5395. The system of claim 5392, wherein heatprovided by the first oxidizer transfers in the first conduit in a samedirection as heat provided by the second oxidizer.
 5396. The system ofclaim 5383, wherein the oxidizer is configurable to oxidize fuel togenerate heat, and further comprising a recycle conduit configurable torecycle at least some of the fuel in the conduit to a fuel source. 5397.The system of claim 5383, wherein the oxidizer comprises a firstoxidizer positioned in the conduit and a second oxidizer positioned inan annulus formed between a wall of the conduit and a wall of theopening, wherein the oxidizers are configurable to oxidize fuel togenerate heat, and further comprising: a first recycle conduitconfigurable to recycle at least some of the fuel in the conduit to thesecond oxidizer; and a second recycle conduit configurable to recycle atleast some of the fuel in the annulus to the first oxidizer.
 5398. Thesystem of claim 5383, further comprising insulation positionableproximate the oxidizer.
 5399. An in situ method for heating an oil shaleformation, comprising: providing heat to a conduit positioned in anopening in the formation, wherein a first end of the opening contacts anearth surface at a first location, and wherein a second end of theopening contacts the earth surface at a second location; and allowingthe heat in the conduit to transfer through the opening and to asurrounding portion of the formation.
 5400. The method of claim 5399,further comprising: providing fuel to an oxidizer; oxidizing at leastsome of the fuel; and allowing oxidation products to migrate through theopening, wherein the oxidation products comprise heat.
 5401. The methodof claim 5400, wherein the fuel is provided to the oxidizer proximatethe first location, and wherein the oxidation products migrate towardsthe second location.
 5402. The method of claim 5399, wherein theoxidizer comprises a ring burner.
 5403. The method of claim 5399,wherein the oxidizer comprises an inline burner.
 5404. The method ofclaim 5399, further comprising recycling at least some fuel in theconduit.
 5405. A system configurable to provide heat to an oil shaleformation, comprising: a conduit positionable in an opening in theformation, wherein a first end of the opening contacts an earth surfaceat a first location, wherein a second end of the opening contacts theearth surface at a second location; an annulus formed between a wall ofthe conduit and a wall of the opening; and a oxidizer configurable toprovide heat to a selected section of the formation by transferring heatthrough the annulus.
 5406. The system of claim 5405, wherein heat fromthe oxidizer pyrolyzes at least some hydrocarbons in the selectedsection.
 5407. The system of claim 5405, wherein the conduit ispositioned in the opening.
 5408. The system of claim 5405, wherein theoxidizer comprises a first oxidizer and a second oxidizer, wherein thesecond oxidizer is positioned in the conduit, and wherein the secondoxidizer is configured to heat the selected section.
 5409. The system ofclaim 5408, wherein heat provided by the first oxidizer transfers in thefirst conduit in a direction opposite of heat provided by the secondoxidizer.
 5410. The system of claim 5405, wherein the oxidizer comprisesa ring burner.
 5411. The system of claim 5405, wherein the oxidizercomprises an inline burner.
 5412. The system of claim 5405, wherein theoxidizer is configurable to oxidize fuel to generate heat, and furthercomprising a recycle conduit configurable to recycle at least some ofthe fuel in the conduit to a fuel source.
 5413. The system of claim5405, further comprising insulation positionable proximate the oxidizer.5414. The system of claim 5405, wherein the conduit is positioned in theopening.
 5415. The system of claim 5405, wherein the oxidizer ispositioned in the annulus, and wherein the oxidizer is configured toheat the selected section.
 5416. The system of claim 5405, wherein theoxidizer comprises a first oxidizer and a second oxidizer.
 5417. Thesystem of claim 5416, wherein heat provided by the first oxidizertransfers through the opening in a direction opposite of heat providedby the second oxidizer.
 5418. The system of claim 5416, wherein a firstmixture of oxidation products generated by the first oxidizer flowscountercurrent to a second mixture of oxidation products generated bythe second heater.
 5419. The system of claim 5416, wherein fuel isoxidized by the oxidizers to generate heat, and further comprising afirst recycle conduit to recycle fuel in the first conduit proximate thesecond location to the second conduit.
 5420. The system of claim 5416,wherein fuel is oxidized by the oxidizers to generate heat, and furthercomprising a second recycle conduit to recycle fuel in the secondconduit proximate the first location to the first conduit.
 5421. Thesystem of claim 5405, wherein the oxidizer is configurable to oxidizefuel to generate heat, and further comprising a recycle conduitconfigurable to recycle at least some of the fuel in the annulus to afuel source.
 5422. The system of claim 5405, further comprisinginsulation positionable proximate the oxidizer.
 5423. The system ofclaim 5405, further comprising a casing, wherein the conduit ispositionable in the casing.
 5424. The system of claim 5405, wherein theoxidizer comprises a first oxidizer positioned in the annulus and asecond oxidizer positioned in the conduit, wherein the oxidizers areconfigurable to oxidize fuel to generate heat, and further comprising: afirst recycle conduit configurable to recycle at least some of the fuelin the annulus to the second oxidizer; and a second recycle conduitconfigurable to recycle at least some of the fuel in the conduit to thefirst oxidizer.
 5425. An in situ method for heating an oil shaleformation, comprising: providing heat to an annulus formed between awall of an opening in the formation and a wall of a conduit in theopening, wherein a first end of the opening contacts an earth surface ata first location, and wherein a second end of the opening contacts theearth surface at a second location; and allowing the heat in the annulusto transfer through the opening and to a surrounding portion of theformation.
 5426. The method of claim 5425, further comprising: providingfuel to an oxidizer; oxidizing at least some of the fuel; and allowingoxidation products to migrate through the opening, wherein the oxidationproducts comprise heat.
 5427. The method of claim 5426, wherein the fuelis provided the oxidizer proximate the first location, and wherein theoxidation products migrate towards the second location.
 5428. The methodof claim 5425, wherein the oxidizer comprises a ring burner.
 5429. Themethod of claim 5425, wherein the oxidizer comprises an inline burner.5430. The method of claim 5425, further comprising recycling at leastsome fuel in the conduit.
 5431. A system configurable to provide heat toan oil shale formation, comprising: a first conduit positionable in anopening in the formation, wherein a first end of the opening contacts anearth surface at a first location, wherein a second end of the openingcontacts the earth surface at a second location; a second conduitpositionable in the opening; a first oxidizer configurable to provideheat to a selected section of the formation by transferring heat throughthe first conduit; and a second oxidizer configurable to provide heat tothe selected section of the formation by transferring heat through thesecond conduit.
 5432. The system of claim 5431, wherein the firstoxidizer is positionable in the first conduit.
 5433. The system of claim5431, wherein the second oxidizer is positionable in the second conduit.5434. The system of claim 5431, further comprising a casing positionablein the opening.
 5435. The system of claim 5431, wherein at least aportion of the second conduit is positionable in the first conduit, andfurther comprising an annulus formed between a wall of the first conduitand a wall of the second conduit.
 5436. The system of claim 5431,wherein a portion of the second conduit is positionable proximate aportion of the first conduit.
 5437. The system of claim 5431, whereinthe first oxidizer or the second oxidizer provide heat to at least aportion of the formation.
 5438. The system of claim 5431, wherein thefirst oxidizer and the second oxidizer provide heat to at least aportion of the formation concurrently.
 5439. The system of claim 5431,wherein the first oxidizer is positioned in the first conduit, whereinthe second oxidizer is positioned in the second conduit, wherein thefirst oxidizer and the second oxidizer comprise oxidizers, and wherein afirst flow of oxidation products from the first oxidizer flows in adirection opposite of a second flow of oxidation products from thesecond oxidizer.
 5440. The system of claim 5431, further comprising: afirst recycle conduit configurable to recycle at least some of the fuelin the first conduit to the second oxidizer; and a second recycleconduit configurable to recycle at least some of the fuel in the secondconduit to the first oxidizer.
 5441. An in situ method for heating anoil shale formation, comprising: providing heat to a first conduitpositioned in an opening in the formation, wherein a first end of theopening contacts an earth surface at a first location, and wherein asecond end of the opening contacts the earth surface at a secondlocation; providing heat to a second conduit positioned in the openingin the formation; allowing the heat in the first conduit to transferthrough the opening and to a surrounding portion of the formation; andallowing the heat in the second conduit to transfer through the openingand to a surrounding portion of the formation;
 5442. The method of claim5441, wherein providing heat to the first conduit comprises providingfuel to an oxidizer.
 5443. The method of claim 5441, wherein providingheat to the second conduit comprises providing fuel to an oxidizer.5444. The method of claim 5441, wherein the first fuel is provided tothe first conduit proximate the first location, and wherein the secondfuel is provided to the second conduit proximate the second location.5445. The method of claim 5441, wherein the first oxidizer or the secondoxidizer comprises a ring burner.
 5446. The method of claim 5441,wherein the first oxidizer or the second oxidizer an inline burner.5447. The method of claim 5441, further comprising: transferring heatthrough the first conduit in a first direction; and transferring heat inthe second conduit in a second direction.
 5448. The method of claim5441, further comprising recycling at least some fuel in the firstconduit to the second conduit; and recycling at least some fuel in thesecond conduit to the first conduit.
 5449. A system configurable toprovide heat to an oil shale formation, comprising: a first conduitpositionable in an opening in the formation, wherein a first end of theopening contacts an earth surface at a first location, wherein a secondend of the opening contacts the earth surface at a second location; asecond conduit positionable in the first conduit; and at least onesurface unit configurable to provide heat to the first conduit. 5450.The system of claim 5449, wherein the surface unit comprises a furnace.5451. The system of claim 5449, wherein the surface unit comprises aburner.
 5452. The system of claim 5449, wherein at least one surfaceunit is configurable to provide heat to the second conduit.
 5453. Thesystem of claim 5452, wherein the first conduit and the second conduitprovide heat to at least a portion of the formation.
 5454. The system ofclaim 5452, wherein the first conduit provides heat to at least aportion of the formation.
 5455. The system of claim 5452, wherein thesecond conduit provides heat to at least a portion of the formation.5456. The system of claim 5449, further comprising a casing positionablein the opening.
 5457. The method of claim 5449, wherein the firstconduit and the second conduit are concentric.
 5458. An in situ methodfor heating an oil shale formation, comprising: heating a fluid using atleast one surface unit; providing the heated fluid to a first conduitwherein a portion of the first conduit is positioned in an opening inthe formation, wherein a first end of the opening contacts an earthsurface at a first location, and wherein a second end of the openingcontacts the earth surface at a second location; allowing the heatedfluid to flow into a second conduit, wherein the first conduit ispositioned within the second conduit; and allowing heat from the firstand second conduit to transfer to a portion of the formation.
 5459. Themethod of claim 5458, further comprising providing additional heat tothe heated fluid using at least one surface unit proximate the secondlocation.
 5460. The method of claim 5458, wherein the fluid comprises anoxidizing fluid.
 5461. The method of claim 5458, wherein the fluidcomprises air.
 5462. The method of claim 5458, wherein the fluidcomprises flue gas.
 5463. The method of claim 5458, wherein the fluidcomprises steam.
 5464. The method of claim 5458, wherein the fluidcomprises fuel.
 5465. The method of claim 5458, further comprisingcompressing the fluid prior to heating.
 5466. The method of claim 5458,wherein the surface unit comprises a furnace.
 5467. The method of claim5458, wherein the surface unit comprises an indirect furnace.
 5468. Themethod of claim 5458, wherein the surface unit comprises a burner. 5469.The method of claim 5458, wherein the first conduit and the secondconduit are concentric.
 5470. A system configurable to provide heat toan oil shale formation, comprising: a conduit positionable in at least aportion of an opening in the formation, wherein a first end of theopening contacts an earth surface at a first location, and wherein asecond end of the opening contacts the earth surface at a secondlocation; and at least two oxidizers configurable to provide heat to aportion of the formation.
 5471. The system of claim 5470, wherein heatfrom the oxidizers pyrolyzes at least some hydrocarbons in the selectedsection.
 5472. The system of claim 5470, wherein the conduit comprises afuel conduit.
 5473. The system of claim 5470, wherein at least oneoxidizer is positionable proximate the conduit.
 5474. The system ofclaim 5470, wherein at least one oxidizer comprises a ring burner. 5475.The system of claim 5470, wherein at least one oxidizer comprises aninline burner.
 5476. The system of claim 5470, further comprisinginsulation positionable proximate at least one oxidizer.
 5477. Thesystem of claim 5470, further comprising a casing comprising insulationproximate at least one oxidizer.
 5478. An in situ method for heating anoil shale formation, comprising: providing fuel to a conduit positionedin an opening in the formation, wherein a first end of the openingcontacts an earth surface at a first location, and wherein a second endof the opening contacts the earth surface at a second location;providing an oxidizing fluid to the opening; oxidizing fuel in at leastone oxidizer positioned proximate the conduit; and allowing heat totransfer to a portion of the formation.
 5479. The method of claim 5478,further comprising providing steam to the conduit.
 5480. The method ofclaim 5478, further comprising inhibiting coking within the conduit.5481. The method of claim 5478, wherein the oxidizing fluid comprisesair.
 5482. The method of claim 5478, wherein the oxidizing fluidcomprises oxygen.
 5483. The method of claim 5478, further comprisingallowing oxidation products to exit the opening proximate the secondlocation.
 5484. The method of claim 5478, wherein the fuel is providedto proximate the first location, and wherein the oxidation productsmigrate towards the second location.
 5485. The method of claim 5478,wherein the oxidizer comprises a ring burner.
 5486. The method of claim5478, wherein the oxidizer comprises an inline burner.
 5487. The methodof claim 5478, further comprising recycling at least some fuel in theconduit.
 5488. The system of claim 5478, wherein the opening comprises acasing and further comprising insulating a portion of the casingproximate at least one oxidizer.
 5489. The system of claim 5478, furthercomprising at least two oxidizers, wherein the oxidizers are positionedabout 30 m apart.
 5490. A system configurable to provide heat to an oilshale formation, comprising: a conduit positionable in at least aportion of an opening in the formation, wherein a first end of theopening contacts an earth surface at a first location, and wherein asecond end of the opening contacts the earth surface at a secondlocation; and an oxidizing fluid source configurable to provide anoxidizing fluid to a reaction zone of the formation.
 5491. The system ofclaim 5490, wherein the conduit comprises a conductor and wherein theconductor is configured to generate heat during application of anelectrical current to the conduit.
 5492. The system of claim 5490,wherein the conduit comprises a low resistance conductor and wherein atleast some of the low resistance conductor is positionable in anoverburden.
 5493. The system of claim 5490, wherein the oxidizing fluidsource is configurable to provide at least some oxidizing fluid to theconduit at the first location and at the second location.
 5494. Thesystem of claim 5490, wherein the opening is configurable to allowproducts of oxidation to be produced from the formation.
 5495. Thesystem of claim 5490, wherein the oxidizing fluid reacts with at leastsome hydrocarbons and wherein the oxidizing fluid source is configurableto provide at least some oxidizing fluid to the first location and tothe second location.
 5496. The system of claim 5490, wherein the heatsource is configurable to heat a reaction zone of the selected sectionto a temperature sufficient to support reaction of hydrocarbons in theselected section with an oxidizing fluid.
 5497. The system of claim5496, wherein the heat source is configurable to provide an oxidizingfluid to the selected section of the formation to generate heat duringuse.
 5498. The system of claim 5496, wherein the generated heattransfers to a pyrolysis zone of the formation.
 5499. The system ofclaim 5490, further comprising an oxidizing fluid source configurable toprovide an oxidizing fluid to the heat source, and wherein the conduitis configurable to provide the oxidizing fluid to the selected sectionof the formation during use.
 5500. The system of claim 5490, wherein theconduit comprises a low resistance conductor and a conductor, andwherein the conductor is further configured to generate heat duringapplication of an electrical current to the conduit.
 5501. An in situmethod for heating an oil shale formation, comprising: providing anelectrical current to a conduit positioned in an opening in theformation; allowing heat to transfer from the conduit to a reaction zoneof the formation; providing at least some oxidizing fluid to theconduit; allowing the oxidizing fluid to transfer from the conduit tothe reaction zone in the formation; allowing the oxidizing fluid tooxidize at least some hydrocarbons in the reaction zone to generateheat; and allowing at least some of the generated heat to transfer to apyrolysis zone in the formation.
 5502. The method of claim 5966, whereinat least a portion of the conduit is configured to generate heat duringapplication of the electrical current to the conduit.
 5503. The methodof claim 5966, further comprising: providing at least some oxidizingfluid to the conduit proximate a first end of the conduit; providing atleast some oxidizing fluid to the conduit proximate a second end of theconduit; and wherein the first end of the conduit is positioned at afirst location on a surface of the formation and wherein the second endof the conduit is positioned at a second location on the surface. 5504.The method of claim 5966, further comprising allowing the oxidizingfluid to move out of the conduit through orifices positioned on theconduit.
 5505. The method of claim 5966, further comprising removingproducts of oxidation through the opening during use.
 5506. The methodof claim 5966, wherein a first end of the opening is positioned at afirst location on a surface of the formation and wherein a second end ofthe opening is positioned at a second location on the surface.
 5507. Themethod of claim 5966, further comprising heating the reaction zone to atemperature sufficient to support reaction of hydrocarbons with anoxidizing fluid.
 5508. The method of claim 5966, further comprisingcontrolling a flow rate of the oxidizing fluid into the formation. 5509.The method of claim 5966, further comprising controlling a temperaturein the pyrolysis zone.
 5510. The method of claim 5966, furthercomprising removing products from oxidation through an opening in theformation during use.
 5511. A method for treating an oil shale formationin situ, comprising: providing heat from one or more heat sources to atleast a portion of the formation; allowing the heat to transfer from theone or more heat sources to a first section of the formation such thatthe heat from the one or more heat sources pyrolyzes at least somehydrocarbons within the first section; and producing a mixture through asecond section of the formation, wherein the produced mixture comprisesat least some pyrolyzed hydrocarbons from the first section, and whereinthe second section comprises a higher permeability than the firstsection.
 5512. The method of claim 5511, wherein the heat provided fromat least one heat source is transferred to the formation substantiallyby conduction.
 5513. The method of claim 5511, wherein the mixture isproduced from the formation when a partial pressure of hydrogen in atleast a portion the formation is at least about 0.5 bars absolute. 5514.The method of claim 5511, wherein at least one heat source comprises aheater.
 5515. The method of claim 5511, further comprising increasingpermeability within the second section by allowing heat to transfer fromthe one or more heat sources to the second section.
 5516. The method ofclaim 5511, wherein the second section has a higher permeability thanthe first section before providing heat to the formation.
 5517. Themethod of claim 5511, wherein the second section comprises an averagepermeability thickness product of greater than about 100 millidarcyfeet.
 5518. The method of claim 5511, wherein the first sectioncomprises an initial average permeability thickness product of less thanabout 10 millidarcy feet.
 5519. The method of claim 5511, wherein thesecond section comprises an average permeability thickness product thatis at least twice an initial average permeability thickness product ofthe first section.
 5520. The method of claim 5511, wherein the secondsection comprises an average permeability thickness product that is atleast ten times an initial average permeability thickness product of thefirst section.
 5521. The method of claim 5511, wherein the one or moreheat sources are placed within at least one uncased wellbore in theformation.
 5522. The method of claim 5521, further comprising allowingat least some hydrocarbons from the first section to propagate throughat least one uncased wellbore into the second section.
 5523. The methodof claim 5521, further comprising producing at least some hydrocarbonsthrough at least one uncased wellbore.
 5524. The method of claim 5511,further comprising forming one or more fractures that propagate betweenthe first section and the second section.
 5525. The method of claim5524, further comprising allowing at least some hydrocarbons from thefirst section to propagate through the one or more fractures into thesecond section.
 5526. The method of claim 5511, further comprisingproducing the mixture from the formation through a production wellplaced in the second section.
 5527. The method of claim 5511, furthercomprising producing the mixture from the formation through a productionwell placed in the first section and the second section.
 5528. Themethod of claim 5511, further comprising inhibiting fracturing of asection of the formation that is substantially adjacent to anenvironmentally sensitive area.
 5529. The method of claim 5511, furthercomprising producing at least some hydrocarbons through the secondsection to maintain a pressure in the formation below a lithostaticpressure of the formation.
 5530. The method of claim 5511, furthercomprising producing at least some hydrocarbons through a productionwell placed in the first section.
 5531. The method of claim 5511,further comprising pyrolyzing at least some hydrocarbons within thesecond section.
 5532. The method of claim 5511, wherein the firstsection and the second section are substantially adjacent.
 5533. Themethod of claim 5511, further comprising allowing migration of fluidsbetween the first second and the second section.
 5534. The method ofclaim 5511, wherein at least one heat source has a thickness of aconductor that is adjusted to provide more heat to the first sectionthan the second section.
 5535. A method for treating an oil shaleformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation, wherein one or more ofsuch heat sources is placed within at least one uncased wellbore in theformation; allowing the heat to transfer from the one or more heatsources to a first section of the formation such that the heat from theone or more heat sources pyrolyzes at least some hydrocarbons within thefirst section; and producing a mixture through a second section of theformation, wherein the produced mixture comprises at least somepyrolyzed hydrocarbons from the first section, and wherein the secondsection comprises a higher permeability than the first section. 5536.The method of claim 5521, further comprising allowing at least somehydrocarbons from the first section to propagate through at least oneuncased wellbore into the second section.
 5537. The method of claim5521, further comprising producing at least some hydrocarbons through atleast one uncased wellbore.
 5538. A method of using a computer systemfor modeling an in situ process for treating an oil shale formation,comprising: providing at least one property of the formation to thecomputer system; providing at least one operating condition of theprocess to the computer system, wherein the in situ process comprisesproviding heat from one or more heat sources to at least one portion ofthe formation, and wherein the in situ process comprises allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation; and assessing at least one process characteristic ofthe in situ process using a simulation method on the computer system,and using at least one property of the formation and at least oneoperating condition.
 5539. The method of claim 5538, wherein at leastone process characteristic is assessed as function of time.
 5540. Themethod of claim 5538, wherein the simulation method is a body-fittedfinite difference simulation method.
 5541. The method of claim 5538,wherein the simulation method is a space-fitted finite differencesimulation method.
 5542. The method of claim 5538, wherein thesimulation method is a reservoir simulation method.
 5543. The method ofclaim 5538, wherein the simulation method simulates heat transfer byconduction.
 5544. The method of claim 5538, wherein the simulationmethod simulates heat transfer by convection. 5545 The method of claim5538, wherein the simulation method simulates heat transfer byradiation.
 5546. The method of claim 5538, wherein the simulation methodsimulates heat transfer in a near wellbore region.
 5547. The method ofclaim 5538, wherein the simulation method assesses a temperaturedistribution in the formation.
 5548. The method of claim 5538, whereinat least one property of the formation comprises one or more materialsfrom the formation.
 5549. The method of claim 5548, wherein one materialcomprises mineral matter.
 5550. The method of claim 5548, wherein onematerial comprises organic matter.
 5551. The method of claim 5538,wherein at least one property of the formation comprises one or morephases.
 5552. The method of claim 5551, wherein one phase comprises awater phase.
 5553. The method of claim 5551, wherein one phase comprisesan oil phase.
 5554. The method of claim 5553, wherein the oil phasecomprises one or more components.
 5555. The method of claim 5551,wherein one phase comprises a gas phase.
 5556. The method of claim 5555,wherein the gas phase comprises one or more components.
 5557. The methodof claim 5538, wherein at least one property of the formation comprisesa porosity of the formation.
 5558. The method of claim 5538, wherein atleast one property of the formation comprises a permeability of theformation.
 5559. The method of claim 5558, wherein the permeabilitydepends on the composition of the formation.
 5560. The method of claim5538, wherein at least one property of the formation comprises asaturation of the formation.
 5561. The method of claim 5538, wherein atleast one property of the formation comprises a density of theformation.
 5562. The method of claim 5538, wherein at least one propertyof the formation comprises a thermal conductivity of the formation.5563. The method of claim 5538, wherein at least one property of theformation comprises a volumetric heat capacity of the formation. 5564.The method of claim 5538, wherein at least one property of the formationcomprises a compressibility of the formation.
 5565. The method of claim5538, wherein at least one property of the formation comprises acomposition of the formation.
 5566. The method of claim 5538, wherein atleast one property of the formation comprises a thickness of theformation.
 5567. The method of claim 5538, wherein at least one propertyof the formation comprises a depth of the formation.
 5568. The method ofclaim 5538, wherein at least one property comprises one or more chemicalcomponents.
 5569. The method of claim 5568, wherein one componentcomprises a pseudo-component.
 5570. The method of claim 5538, wherein atleast property comprises one or more kinetic parameters.
 5571. Themethod of claim 5538, wherein at least one property comprises one ormore chemical reactions.
 5572. The method of claim 5571, wherein a rateof at least one chemical reaction depends on a pressure of theformation.
 5573. The method of claim 5571, wherein a rate of at leastone chemical reaction depends on a temperature of the formation. 5574.The method of claim 5571, wherein at least one chemical reactioncomprises a pre-pyrolysis water generation reaction.
 5575. The method ofclaim 5571, wherein at least one chemical reaction comprises ahydrocarbon generating reaction.
 5576. The method of claim 5571, whereinat least one chemical reaction comprises a coking reaction.
 5577. Themethod of claim 5571, wherein at least one chemical reaction comprise acracking reaction.
 5578. The method of claim 5571, wherein at least onechemical reaction comprises a synthesis gas reaction.
 5579. The methodof claim 5538, wherein at least one process characteristic comprises anAPI gravity of produced fluids.
 5580. The method of claim 5538, whereinat least one process characteristic comprises an olefin content ofproduced fluids.
 5581. The method of claim 5538, wherein at least oneprocess characteristic comprises a carbon number distribution ofproduced fluids.
 5582. The method of claim 5538, wherein at least oneprocess characteristic comprises an ethene to ethane ratio of producedfluids.
 5583. The method of claim 5538, wherein at least one processcharacteristic comprises an atomic carbon to hydrogen ratio of producedfluids.
 5584. The method of claim 5538, wherein at least one processcharacteristic comprises a ratio of non-condensable hydrocarbons tocondensable hydrocarbons of produced fluids.
 5585. The method of claim5538, wherein at least one process characteristic comprises a pressurein the formation
 5586. The method of claim 5538, wherein at least oneprocess characteristic comprises total mass recovery from the formation.5587. The method of claim 5538, wherein at least one processcharacteristic comprises a production rate of fluid produced from theformation.
 5588. The method of claim 5538, wherein at least oneoperating condition comprises a pressure.
 5589. The method of claim5538, wherein at least one operating condition comprises a temperature.5590. The method of claim 5538, wherein at least one operating conditioncomprises a heating rate.
 5591. The method of claim 5538, wherein atleast one operating condition comprises a process time.
 5592. The methodof claim 5538, wherein at least one operating condition comprises alocation of producer wells.
 5593. The method of claim 5538, wherein atleast one operating condition comprises an orientation of producerwells.
 5594. The method of claim 5538, wherein at least one operatingcondition comprises a ratio of producer wells to heater wells.
 5595. Themethod of claim 5538, wherein at least one operating condition comprisesa spacing between heater wells.
 5596. The method of claim 5538, whereinat least one operating condition comprises a distance between anoverburden and horizontal heater wells.
 5597. The method of claim 5538,wherein at least one operating condition comprises a pattern of heaterwells.
 5598. The method of claim 5538, wherein at least one operatingcondition comprises an orientation of heater wells.
 5599. A method ofusing a computer system for modeling an in situ process for treating anoil shale formation, comprising: simulating a heat input rate to theformation from two or more heat sources on the computer system, whereinheat is allowed to transfer from the heat sources to a selected sectionof the formation; providing at least one desired parameter of the insitu process to the computer system; and controlling the heat input ratefrom the heat sources to achieve at least one desired parameter. 5600.The method of claim 5599, wherein the heat is allowed to transfer fromthe heat sources substantially by conduction.
 5601. The method of claim5599, wherein the heat input rate is simulated with a body-fitted finitedifference simulation method.
 5602. The method of claim 5599, whereinsimulating the heat input rate from two or more heat sources comprisessimulating a model of one or more heat sources with symmetry boundaryconditions.
 5603. The method of claim 5599, wherein superposition ofheat from the two or more heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 5604. Themethod of claim 5599, wherein at least one desired parameter comprises aselected process characteristic.
 5605. The method of claim 5599, whereinat least one desired parameter comprises a selected temperature. 5606.The method of claim 5599, wherein at least one desired parametercomprises a selected heating rate.
 5607. The method of claim 5599,wherein at least one desired parameter comprises a desired productmixture produced from the formation.
 5608. The method of claim 5599,wherein at least one desired parameter comprises a desired productmixture produced from the formation, and wherein the desired productmixture comprises a selected composition.
 5609. The method of claim5599, wherein at least one desired parameter comprises a selectedpressure.
 5610. The method of claim 5599, wherein at least one desiredparameter comprises a selected heating time.
 5611. The method of claim5599, wherein at least one desired parameter comprises a marketparameter.
 5612. The method of claim 5599, wherein at least one desiredparameter comprises a price of crude oil.
 5613. The method of claim5599, wherein at least one desired parameter comprises an energy cost.5614. The method of claim 5599, wherein at least one desired parametercomprises a selected molecular hydrogen to carbon monoxide volume ratio.5615. A method of using a computer system for modeling an in situprocess for treating an oil shale formation, comprising: providing atleast one heat input property to the computer system; assessing heatinjection rate data for the formation using a first simulation method onthe computer system; providing at least one property of the formation tothe computer system; assessing at least one process characteristic ofthe in situ process from the heat injection rate data and at least oneproperty of the formation using a second simulation method; and whereinthe in situ process comprises providing heat from one or more heatsources to at least one portion of the formation, and wherein the insitu process comprises allowing the heat to transfer from the one ormore heat sources to a selected section of the formation
 5616. Themethod of claim 5615, wherein at least one process characteristic isassessed as a function of time.
 5617. The method of claim 5615, whereinassessing heat injection rate data comprises simulating heating of theformation.
 5618. The method of claim 5615, wherein the heating iscontrolled to obtain a desired parameter.
 5619. The method of claim5615, wherein determining at least one process characteristic comprisessimulating heating of the formation.
 5620. The method of claim 5619,wherein the heating is controlled to obtain a desired parameter. 5621.The method of claim 5615, wherein the first simulation method is abody-fitted finite difference simulation method.
 5622. The method ofclaim 5615, wherein the second simulation method is a space-fittedfinite difference simulation method.
 5623. The method of claim 5615,wherein the second simulation method is a reservoir simulation method.5624. The method of claim 5615, wherein the first simulation methodsimulates heat transfer by conduction.
 5625. The method of claim 5615,wherein the first simulation method simulates heat transfer byconvection.
 5626. The method of claim 5615, wherein the first simulationmethod simulates heat transfer by radiation.
 5627. The method of claim5615, wherein the second simulation method simulates heat transfer byconduction.
 5628. The method of claim 5615, wherein the secondsimulation method simulates heat transfer by convection.
 5629. Themethod of claim 5615, wherein the first simulation method simulates heattransfer in a near wellbore region.
 5630. The method of claim 5615,wherein the first simulation method determines a temperaturedistribution in the formation.
 5631. The method of claim 5615, whereinat least one heat input property comprises a property of the formation.5632. The method of claim 5615, wherein at least one heat input propertycomprises a heat transfer property.
 5633. The method of claim 5615,wherein at least one heat input property comprises an initial propertyof the formation.
 5634. The method of claim 5615, wherein at least oneheat input property comprises a heat capacity.
 5635. The method of claim5615, wherein at least one heat input property comprises a thermalconductivity.
 5636. The method of claim 5615, wherein the heat injectionrate data comprises a temperature distribution within the formation.5637. The method of claim 5615, wherein the heat injection rate datacomprises a heat input rate.
 5638. The method of claim 5637, wherein theheat input rate is controlled to maintain a specified maximumtemperature at a point in the formation.
 5639. The method of claim 5615,wherein the heat injection rate data comprises heat flux data.
 5640. Themethod of claim 5615, wherein at least one property of the formationcomprises one or more materials in the formation.
 5641. The method ofclaim 5640, wherein one material comprises mineral matter.
 5642. Themethod of claim 5640, wherein one material comprises organic matter.5643. The method of claim 5615, wherein at least one property of theformation comprises one or more phases.
 5644. The method of claim 5643,wherein one phase comprises a water phase.
 5645. The method of claim5643, wherein one phase comprises an oil phase.
 5646. The method ofclaim 5645, wherein the oil phase comprises one or more components.5647. The method of claim 5643, wherein one phase comprises a gas phase.5648. The method of claim 5647, wherein the gas phase comprises one ormore components.
 5649. The method of claim 5615, wherein at least oneproperty of the formation comprises a porosity of the formation. 5650.The method of claim 5615, wherein at least one property of the formationcomprises a permeability of the formation.
 5651. The method of claim5650, wherein the permeability depends on the composition of theformation.
 5652. The method of claim 5615, wherein at least one propertyof the formation comprises a saturation of the formation.
 5653. Themethod of claim 5615, wherein at least one property of the formationcomprises a density of the formation.
 5654. The method of claim 5615,wherein at least one property of the formation comprises a thermalconductivity of the formation.
 5655. The method of claim 5615, whereinat least one property of the formation comprises a volumetric heatcapacity of the formation.
 5656. The method of claim 5615, wherein atleast one property of the formation comprises a compressibility of theformation.
 5657. The method of claim 5615, wherein at least one propertyof the formation comprises a composition of the formation.
 5658. Themethod of claim 5615, wherein at least one property of the formationcomprises a thickness of the formation.
 5659. The method of claim 5615,wherein at least one property of the formation comprises a depth of theformation.
 5660. The method of claim 5615, wherein at least one propertyof the formation comprises one or more chemical components.
 5661. Themethod of claim 5660, wherein at least one chemical component comprisesa pseudo-component.
 5662. The method of claim 5615, wherein at least oneproperty of the formation comprises one or more kinetic parameters.5663. The method of claim 5615, wherein at least one property of theformation comprises one or more chemical reactions.
 5664. The method ofclaim 5663, wherein a rate of at least one chemical reaction depends ona pressure of the formation.
 5665. The method of claim 5663, wherein arate of at least one chemical reaction depends on a temperature of theformation.
 5666. The method of claim 5663, wherein at least one chemicalreaction comprises a pre-pyrolysis water generation reaction.
 5667. Themethod of claim 5663, wherein at least one chemical reaction comprises ahydrocarbon generating reaction.
 5668. The method of claim 5663, whereinat least one chemical reaction comprises a coking reaction.
 5669. Themethod of claim 5663, wherein at least one chemical reaction comprises acracking reaction.
 5670. The method of claim 5663, wherein at least onechemical reaction comprises a synthesis gas reaction.
 5671. The methodof claim 5615, wherein at least one process characteristic comprises anAPI gravity of produced fluids.
 5672. The method of claim 5615, whereinat least one process characteristic comprises an olefin content ofproduced fluids.
 5673. The method of claim 5615, wherein at least oneprocess characteristic comprises a carbon number distribution ofproduced fluids.
 5674. The method of claim 5615, wherein at least oneprocess characteristic comprises an ethene to ethane ratio of producedfluids.
 5675. The method of claim 5615, wherein at least one processcharacteristic comprises an atomic carbon to hydrogen ratio of producedfluids.
 5676. The method of claim 5615, wherein at least one processcharacteristic comprises a ratio of non-condensable hydrocarbons tocondensable hydrocarbons of produced fluids.
 5677. The method of claim5615, wherein at least one process characteristic comprises a pressurein the formation.
 5678. The method of claim 5615, wherein at least oneprocess characteristic comprises a total mass recovery from theformation.
 5679. The method of claim 5615, wherein at least one processcharacteristic comprises a production rate of fluid produced from theformation.
 5680. The method of claim 5615, further comprising: assessingmodified heat injection rate data using the first simulation method at aspecified time of the second simulation method based on at least oneheat input property of the formation at the specified time; assessing atleast one process characteristic of the in situ process as a function oftime from the modified heat injection rate data and at least oneproperty of the formation at the specified time using the secondsimulation method.
 5681. A method of using a computer system formodeling an in situ process for treating an oil shale formation,comprising: providing one or more model parameters for the in situprocess to the computer system; assessing one or more simulated processcharacteristics based on one or more model parameters using a simulationmethod; modifying one or more model parameters such that at least onesimulated process characteristic matches or approximates at least onereal process characteristic; assessing one or more modified simulatedprocess characteristics based on the modified model parameters; andwherein the in situ process comprises providing heat from one or moreheat sources to at least one portion of the formation, and wherein thein situ process comprises allowing the heat to transfer from the one ormore heat sources to a selected section of the formation.
 5682. Themethod of claim 5681, further comprising using the simulation methodwith the modified model parameters to determine at least one operatingcondition of the in situ process to achieve a desired parameter. 5683.The method of claim 5681, wherein the simulation method comprises abody-fitted finite difference simulation method.
 5684. The method ofclaim 5681, wherein the simulation method comprises a space-fittedfinite difference simulation method.
 5685. The method of claim 5681,wherein the simulation method comprises a reservoir simulation method.5686. The method of claim 5681, wherein the real process characteristicscomprise process characteristics obtained from laboratory experiments ofthe in situ process.
 5687. The method of claim 5681, wherein the realprocess characteristics comprise process characteristics obtained fromfield test experiments of the in situ process.
 5688. The method of claim5681, further comprising comparing the simulated process characteristicsto the real process characteristics as a function of time.
 5689. Themethod of claim 5681, further comprising associating differences betweenthe simulated process characteristics and the real processcharacteristics with one or more model parameters.
 5690. The method ofclaim 5681, wherein at least one model parameter comprises a chemicalcomponent.
 5691. The method of claim 5681, wherein at least one modelparameter comprises a kinetic parameter.
 5692. The method of claim 5691,wherein the kinetic parameter comprises an order of a reaction. 5693.The method of claim 5691, wherein the kinetic parameter comprises anactivation energy.
 5694. The method of claim 5691, wherein the kineticparameter comprises a reaction enthalpy.
 5695. The method of claim 5691,wherein the kinetic parameter comprises a frequency factor.
 5696. Themethod of claim 5681, wherein at least one model parameter comprises achemical reaction.
 5697. The method of claim 5696, wherein at least onechemical reaction comprises a pre-pyrolysis water generation reaction.5698. The method of claim 5696, wherein at least one chemical reactioncomprises a hydrocarbon generating reaction.
 5699. The method of claim5696, wherein at least one chemical reaction comprises a cokingreaction.
 5700. The method of claim 5696, wherein at least one chemicalreaction comprises a cracking reaction.
 5701. The method of claim 5696,wherein at least one chemical reaction comprises a synthesis gasreaction.
 5702. The method of claim 5681, wherein one or more modelparameters comprise one or more properties.
 5703. The method of claim5681, wherein at least one model parameter comprises a relationship forthe dependence of a property on a change in conditions in the formation.5704. The method of claim 5681, wherein at least one model parametercomprises an expression for the dependence of porosity on pressure inthe formation.
 5705. The method of claim 5681, wherein at least onemodel parameter comprises an expression for the dependence ofpermeability on porosity.
 5706. The method of claim 5681, wherein atleast one model parameter comprises an expression for the dependence ofthermal conductivity on composition of the formation.
 5707. A method ofusing a computer system for modeling an in situ process for treating anoil shale formation, comprising: assessing at least one operatingcondition of the in situ process using a simulation method based on oneor more model parameter; modifying at least one model parameter suchthat at least one simulated process characteristic of the in situprocess matches or approximates at least one real process characteristicof the in situ process; assessing one or more modified simulated processcharacteristics based on the modified model parameters; and wherein thein situ process comprises providing heat from one or more heat sourcesto at least one portion of the formation, and wherein the in situprocess comprises allowing the heat to transfer from the one or moreheat sources to a selected section of the formation
 5708. The method ofclaim 5707, wherein at least one operating condition is assessed toachieve at least one desired parameter.
 5709. The method of claim 5707,wherein the real process characteristic comprises a processcharacteristic from a field test of the in situ process.
 5710. Themethod of claim 5707, wherein the simulation method comprises abody-fitted finite difference simulation method.
 5711. The method ofclaim 5707, wherein the simulation method comprises a space-fittedfinite difference simulation method.
 5712. The method of claim 5707,wherein the simulation method comprises a reservoir simulation method.5713. A method of modeling a process of treating an oil shale formationin situ using a computer system, comprising: providing one or more modelparameters to the computer system; assessing one or more first processcharacteristics based on the one or more model parameters using a firstsimulation method on the computer system; assessing one or more secondprocess characteristics based on one or more model parameters using asecond simulation method on the computer system; modifying one or moremodel parameters such that at least one first process characteristicmatches or approximates at least one second process characteristic; andwherein the in situ process comprises providing heat from one or moreheat sources to at least one portion of the formation, and wherein thein situ process comprises allowing the heat to transfer from the one ormore heat sources to a selected section of the formation.
 5714. Themethod of claim 5713, further comprising assessing one or more thirdprocess characteristics based on the one or more modified modelparameters using the second simulation method.
 5715. The method of claim5713, wherein modifying one or more model parameters such that at leastone first process characteristic matches or approximates at least onesecond process characteristic further comprises: assessing at least oneset of first process characteristics based on at least one set ofmodified model parameters using the first simulation method; andassessing the set of modified model parameters that results in at leastone first process characteristic that matches or approximates at leastone second process characteristic.
 5716. The method of claim 5713,wherein the first simulation method comprises a body-fitted finitedifference simulation method.
 5717. The method of claim 5713, whereinthe second simulation method comprises a space-fitted finite differencesimulation method.
 5718. The method of claim 5713, wherein at least onefirst process characteristic comprises a process characteristic at asharp interface in the formation.
 5719. The method of claim 5713,wherein at least one first process characteristic comprises a processcharacteristic at a combustion front in the formation.
 5720. The methodof claim 5713, wherein modifying the one or more model parameterscomprises changing the order of a chemical reaction.
 5721. The method ofclaim 5713, wherein modifying the one or more model parameters comprisesadding one or more chemical reactions.
 5722. The method of claim 5713,wherein modifying the one or more model parameters comprises changing anactivation energy.
 5723. The method of claim 5713, wherein modifying theone or more model parameters comprises changing a frequency factor.5724. A method of using a computer system for modeling an in situprocess for treating an oil shale formation, comprising: providing tothe computer system one or more values of at least one operatingcondition of the in situ process, wherein the in situ process comprisesproviding heat from one or more heat sources to at least one portion ofthe formation, and wherein the in situ process comprises allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation; assessing one or more values of at least one processcharacteristic corresponding to one or more values of at least oneoperating condition using a simulation method; providing a desired valueof at least one process characteristic for the in situ process to thecomputer system; and assessing a desired value of at least one operatingcondition to achieve the desired value of at least one processcharacteristic from the assessed values of at least one processcharacteristic and the provided values of at least one operatingcondition.
 5725. The method of claim 5724, further comprising operatingthe in situ system using the desired value of at least one operatingcondition.
 5726. The method of claim 5724, wherein the process comprisesproviding heat from one or more heat sources to at least one portion ofthe formation.
 5727. The method of claim 5724, wherein the processcomprises allowing heat to transfer from one or more heat sources to aselected section of the formation.
 5728. The method of claim 5724,wherein a value of at least one process characteristic comprises theprocess characteristic as a function of time.
 5729. The method of claim5724, further comprising determining a value of at least one processcharacteristic based on the desired value of at least one operatingcondition using the simulation method.
 5730. The method of claim 5724,wherein determining the desired value of at least one operatingcondition comprises interpolating the desired value from the determinedvalues of at least one process characteristic and the provided values ofat least one operating condition.
 5731. A method of using a computersystem for modeling an in situ process for treating an oil shaleformation, comprising: providing a desired value of at least one processcharacteristic for the in situ process to the computer system, whereinthe in situ process comprises providing heat from one or more heatsources to at least one portion of the formation, and wherein the insitu process comprises allowing the heat to transfer from the one ormore heat sources to a selected section of the formation; and assessinga value of at least one operating condition to achieve the desired valueof at least one process characteristic, wherein such assessing comprisesusing a relationship between at least one process characteristic and atleast one operating condition for the in situ process, wherein suchrelationship is stored on a database accessible by the computer system.5732. The method of claim 5731, further comprising operating the in situsystem using the desired value of at least one operating condition.5733. The method of claim 5731, wherein the process comprises providingheat from one or more heat sources to at least one portion of theformation.
 5734. The method of claim 5731, wherein the process comprisesproviding heat to transfer from one or more heat sources to a selectedsection of the formation.
 5735. The method of claim 5731, wherein therelationship is determined from one or more simulations of the in situprocess using a simulation method.
 5736. The method of claim 5731,wherein the relationship comprises one or more values of at least oneprocess characteristic and corresponding values of at least oneoperating condition.
 5737. The method of claim 5731, wherein therelationship comprises an analytical function.
 5738. The method of claim5731, wherein determining the value of at least one operating conditioncomprises interpolating the value of at least one operating conditionfrom the relationship.
 5739. The method of claim 5731, wherein at leastone process characteristic comprises a selected composition of producedfluids.
 5740. The method of claim 5731, wherein at least one operatingcondition comprises a pressure.
 5741. The method of claim 5731, whereinat least one operating condition comprises a heat input rate.
 5742. Asystem, comprising: a CPU; a data memory coupled to the CPU; and asystem memory coupled to the CPU, wherein the system memory isconfigured to store one or more computer programs executable by the CPU,and wherein the computer programs are executable to implement a methodof using a computer system for modeling an in situ process for treatingan oil shale formation, the method comprising: providing at least oneproperty of the formation to the computer system; providing at least oneoperating condition of the process to the computer system, wherein thein situ process comprises providing heat from one or more heat sourcesto at least one portion of the formation, and wherein the in situprocess comprises allowing the heat to transfer from the one or moreheat sources to a selected section of the formation; and assessing atleast one process characteristic of the in situ process using asimulation method on the computer system, and using at least oneproperty of the formation and at least one operating condition.
 5743. Acarrier medium comprising program instructions, wherein the programinstructions are computer-executable to implement a method comprising:providing at least one property of the formation to the computer system;providing at least one operating condition of the process to thecomputer system, wherein the in situ process comprises providing heatfrom one or more heat sources to at least one portion of the formation,and wherein the in situ process comprises allowing the heat to transferfrom the one or more heat sources to a selected section of theformation; and assessing at least one process characteristic of the insitu process using a simulation method on the computer system, and usingat least one property of the formation and at least one operatingcondition.
 5744. A system, comprising: a CPU; a data memory coupled tothe CPU; and a system memory coupled to the CPU, wherein the systemmemory is configured to store one or more computer programs executableby the CPU, and wherein the computer programs are executable toimplement a method of using a computer system for modeling an in situprocess for treating an oil shale formation, the method comprising:simulating a heat input rate to the formation from two or more heatsources on the computer system, wherein heat is allowed to transfer fromthe heat sources to a selected section of the formation; providing atleast one desired parameter of the in situ process to the computersystem; and controlling the heat input rate from the heat sources toachieve at least one desired parameter.
 5745. A carrier mediumcomprising program instructions, wherein the program instructions arecomputer-executable to implement a method comprising: simulating a heatinput rate to the formation from two or more heat sources on thecomputer system, wherein heat is allowed to transfer from the heatsources to a selected section of the formation; providing at least onedesired parameter of the in situ process to the computer system; andcontrolling the heat input rate from the heat sources to achieve atleast one desired parameter.
 5746. A system, comprising: a CPU; a datamemory coupled to the CPU; and a system memory coupled to the CPU,wherein the system memory is configured to store one or more computerprograms executable by the CPU, and wherein the computer programs areexecutable to implement a method of using a computer system for modelingan in situ process for treating an oil shale formation, the methodcomprising: providing at least one heat input property to the computersystem; assessing heat injection rate data for the formation using afirst simulation method on the computer system; providing at least oneproperty of the formation to the computer system; assessing at least oneprocess characteristic of the in situ process from the heat injectionrate data and at least one property of the formation using a secondsimulation method; and wherein the in situ process comprises providingheat from one or more heat sources to at least one portion of theformation, and wherein the in situ process comprises allowing the heatto transfer from the one or more heat sources to a selected section ofthe formation
 5747. A carrier medium comprising program instructions,wherein the program instructions are computer-executable to implement amethod comprising: providing at least one heat input property to thecomputer system; assessing heat injection rate data for the formationusing a first simulation method on the computer system; providing atleast one property of the formation to the computer system; assessing atleast one process characteristic of the in situ process from the heatinjection rate data and at least one property of the formation using asecond simulation method; and wherein the in situ process comprisesproviding heat from one or more heat sources to at least one portion ofthe formation, and wherein the in situ process comprises allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation
 5748. A system, comprising: a CPU; a data memorycoupled to the CPU; and a system memory coupled to the CPU, wherein thesystem memory is configured to store one or more computer programsexecutable by the CPU, and wherein the computer programs are executableto implement a method of using a computer system for modeling an in situprocess for treating an oil shale formation, the method comprising:providing one or more model parameters for the in situ process to thecomputer system; assessing one or more simulated process characteristicsbased on one or more model parameters using a simulation method;modifying one or more model parameters such that at least one simulatedprocess characteristic matches or approximates at least one real processcharacteristic; assessing one or more modified simulated processcharacteristics based on the modified model parameters; and wherein thein situ process comprises providing heat from one or more heat sourcesto at least one portion of the formation, and wherein the in situprocess comprises allowing the heat to transfer from the one or moreheat sources to a selected section of the formation.
 5749. A carriermedium comprising program instructions, wherein the program instructionsare computer-executable to implement a method comprising: providing oneor more model parameters for the in situ process to the computer system;assessing one or more simulated process characteristics based on one ormore model parameters using a simulation method; modifying one or moremodel parameters such that at least one simulated process characteristicmatches or approximates at least one real process characteristic;assessing one or more modified simulated process characteristics basedon the modified model parameters; and wherein the in situ processcomprises providing heat from one or more heat sources to at least oneportion of the formation, and wherein the in situ process comprisesallowing the heat to transfer from the one or more heat sources to aselected section of the formation.
 5750. A system, comprising: a CPU; adata memory coupled to the CPU; and a system memory coupled to the CPU,wherein the system memory is configured to store one or more computerprograms executable by the CPU, and wherein the computer programs areexecutable to implement a method of using a computer system for modelingan in situ process for treating an oil shale formation, the methodcomprising: assessing at least one operating condition of the in situprocess using a simulation method based on one or more model parameter;modifying at least one model parameter such that at least one simulatedprocess characteristic of the in situ process matches or approximates atleast one real process characteristic of the in situ process; assessingone or more modified simulated process characteristics based on themodified model parameters; and wherein the in situ process comprisesproviding heat from one or more heat sources to at least one portion ofthe formation, and wherein the in situ process comprises allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation simulated process characteristics based on the modifiedmodel parameters.
 5751. A carrier medium comprising programinstructions, wherein the program instructions are computer-executableto implement a method comprising: assessing at least one operatingcondition of the in situ process using a simulation method based on oneor more model parameter; modifying at least one model parameter suchthat at least one simulated process characteristic of the in situprocess matches or approximates at least one real process characteristicof the in situ process; assessing one or more modified simulated processcharacteristics based on the modified model parameters; and wherein thein situ process comprises providing heat from one or more heat sourcesto at least one portion of the formation, and wherein the in situprocess comprises allowing the heat to transfer from the one or moreheat sources to a selected section of the formation
 5752. A system,comprising: a CPU; a data memory coupled to the CPU; and a system memorycoupled to the CPU, wherein the system memory is configured to store oneor more computer programs executable by the CPU, and wherein thecomputer programs are executable to implement a method of using acomputer system for modeling an in situ process for treating an oilshale formation, the method comprising: providing one or more modelparameters to the computer system; assessing one or more first processcharacteristics based on one or more model parameters using a firstsimulation method on the computer system; assessing one or more secondprocess characteristics based on one or more model parameters using asecond simulation method on the computer system; modifying one or moremodel parameters such that at least one first process characteristicmatches or approximates at least one second process characteristic; andwherein the in situ process comprises providing heat from one or moreheat sources to at least one portion of the formation, and wherein thein situ process comprises allowing the heat to transfer from the one ormore heat sources to a selected section of the formation
 5753. A carriermedium comprising program instructions, wherein the program instructionsare computer-executable to implement a method comprising: providing oneor more model parameters to the computer system; assessing one or morefirst process characteristics based on one or more model parametersusing a first simulation method on the computer system; assessing one ormore second process characteristics based on one or more modelparameters using a second simulation method on the computer system;modifying one or more model parameters such that at least one firstprocess characteristic matches at least one second processcharacteristic; and wherein the in situ process comprises providing heatfrom one or more heat sources to at least one portion of the formation,and wherein the in situ process comprises allowing the heat to transferfrom the one or more heat sources to a selected section of theformation.
 5754. A system, comprising: a CPU; a data memory coupled tothe CPU; and a system memory coupled to the CPU, wherein the systemmemory is configured to store one or more computer programs executableby the CPU, and wherein the computer programs are executable toimplement a method of using a computer system for modeling an in situprocess for treating an oil shale formation, the method comprising:providing to the computer system one or more values of at least oneoperating condition of the in situ process, wherein the in situ processcomprises providing heat from one or more heat sources to at least oneportion of the formation, and wherein the in situ process comprisesallowing the heat to transfer from the one or more heat sources to aselected section of the formation; assessing one or more values of atleast one process characteristic corresponding to one or more values ofat least one operating condition using a simulation method; providing adesired value of at least one process characteristic for the in situprocess to the computer system; and assessing a desired value of atleast one operating condition to achieve the desired value of at leastone process characteristic from the assessed values of at least oneprocess characteristic and the provided values of at least one operatingcondition.
 5755. A carrier medium comprising program instructions,wherein the program instructions are computer-executable to implement amethod comprising: providing to the computer system one or more valuesof at least one operating condition of the in situ process, wherein thein situ process comprises providing heat from one or more heat sourcesto at least one portion of the formation, and wherein the in situprocess comprises allowing the heat to transfer from the one or moreheat sources to a selected section of the formation; assessing one ormore values of at least one process characteristic corresponding to oneor more values of at least one operating condition using a simulationmethod; providing a desired value of at least one process characteristicfor the in situ process to the computer system; and assessing a desiredvalue of at least one operating condition to achieve the desired valueof at least one process characteristic from the assessed values of atleast one process characteristic and the provided values of at least oneoperating condition.
 5756. A system, comprising: a CPU; a data memorycoupled to the CPU; and a system memory coupled to the CPU, wherein thesystem memory is configured to store one or more computer programsexecutable by the CPU, and wherein the computer programs are executableto implement a method of using a computer system for modeling an in situprocess for treating an oil shale formation, the method comprising:providing a desired value of at least one process characteristic for thein situ process to the computer system, wherein the in situ processcomprises providing heat from one or more heat sources to at least oneportion of the formation, and wherein the in situ process comprisesallowing the heat to transfer from the one or more heat sources to aselected section of the formation; and assessing a value of at least oneoperating condition to achieve the desired value of at least one processcharacteristic, wherein such assessing comprises using a relationshipbetween at least one process characteristic and at least one operatingcondition for the in situ process, wherein such relationship is storedon a database accessible by the computer system.
 5757. A carrier mediumcomprising program instructions, wherein the program instructions arecomputer-executable to implement a method comprising: providing adesired value of at least one process characteristic for the in situprocess to the computer system, wherein the in situ process comprisesproviding heat from one or more heat sources to at least one portion ofthe formation, and wherein the in situ process comprises allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation; and assessing a value of at least one operatingcondition to achieve the desired value of at least one processcharacteristic, wherein such assessing comprises using a relationshipbetween at least one process characteristic and at least one operatingcondition for the in situ process, wherein such relationship is storedon a database accessible by the computer system.
 5758. A method of usinga computer system for operating an in situ process for treating an oilshale formation, comprising: operating the in situ process using one ormore operating parameters, wherein the in situ process comprisesproviding heat from one or more heat sources to at least one portion ofthe formation, and wherein the in situ process comprises allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation; providing at least one operating parameter of the insitu process to the computer system; and using at least one parameterwith a simulation method and the computer system to provide assessedinformation about the in situ process.
 5759. The method of claim 5758,wherein one or more of the operating parameters comprise a thickness ofa treated portion of the formation.
 5760. The method of claim 5758,wherein one or more of the operating parameters comprise an area of atreated portion of the formation.
 5761. The method of claim 5758,wherein one or more of the operating parameters comprise a volume of atreated portion of the formation.
 5762. The method of claim 5758,wherein one or more of the operating parameters comprise a property ofthe formation.
 5763. The method of claim 5758, wherein one or more ofthe operating parameters comprise a heat capacity of the formation.5764. The method of claim 5758, wherein one or more of the operatingparameters comprise a permeability of the formation.
 5765. The method ofclaim 5758, wherein one or more of the operating parameters comprise adensity of the formation.
 5766. The method of claim 5758, wherein one ormore of the operating parameters comprise a thermal conductivity of theformation.
 5767. The method of claim 5758, wherein one or more of theoperating parameters comprise a porosity of the formation.
 5768. Themethod of claim 5758, wherein one or more of the operating parameterscomprise a pressure.
 5769. The method of claim 5758, wherein one or moreof the operating parameters comprise a temperature.
 5770. The method ofclaim 5758, wherein one or more of the operating parameters comprise aheating rate.
 5771. The method of claim 5758, wherein one or more of theoperating parameters comprise a process time.
 5772. The method of claim5758, wherein one or more of the operating parameters comprises alocation of producer wells.
 5773. The method of claim 5758, wherein oneor more of the operating parameters comprise an orientation of producerwells.
 5774. The method of claim 5758, wherein one or more of theoperating parameters comprise a ratio of producer wells to heater wells.5775. The method of claim 5758, wherein one or more of the operatingparameters comprise a spacing between heater wells.
 5776. The method ofclaim 5758, wherein one or more of the operating parameters comprise adistance between an overburden and horizontal heater wells.
 5777. Themethod of claim 5758, wherein one or more of the operating parameterscomprise a type of pattern of heater wells.
 5778. The method of claim5758, wherein one or more of the operating parameters comprise anorientation of heater wells.
 5779. The method of claim 5758, wherein oneor more of the operating parameters comprise a mechanical property.5780. The method of claim 5758, wherein one or more of the operatingparameters comprise subsidence of the formation.
 5781. The method ofclaim 5758, wherein one or more of the operating parameters comprisefracture progression in the formation.
 5782. The method of claim 5758,wherein one or more of the operating parameters comprise heave of theformation.
 5783. The method of claim 5758, wherein one or more of theoperating parameters comprise compaction of the formation.
 5784. Themethod of claim 5758, wherein one or more of the operating parameterscomprise shear deformation of the formation.
 5785. The method of claim5758, wherein the assessed information comprises information relating toproperties of the formation.
 5786. The method of claim 5758, wherein theassessed information comprises a relationship between one or moreoperating parameters and at least one other operating parameter. 5787.The method of claim 5758, wherein the computer system is remote from thein situ process.
 5788. The method of claim 5758, wherein the computersystem is located at or near the in situ process.
 5789. The method ofclaim 5758, wherein at least one parameter is provided to the computersystem using hardwire communication.
 5790. The method of claim 5758,wherein at least one parameter is provided to the computer system usinginternet communication.
 5791. The method of claim 5758, wherein at leastone parameter is provided to the computer system using wirelesscommunication.
 5792. The method of claim 5758, wherein the one or moreparameters are monitored using sensors in the formation.
 5793. Themethod of claim 5758, wherein at least one parameter is providedautomatically to the computer system.
 5794. The method of claim 5758,wherein using at least one parameter with a simulation method comprisesperforming a simulation and obtaining properties of the formation. 5795.A method of using a computer system for operating an in situ process fortreating an oil shale formation, comprising: operating the in situprocess using one or more operating parameters, wherein the in situprocess comprises providing heat from one or more heat sources to atleast one portion of the formation, and wherein the in situ processcomprises allowing the heat to transfer from the one or more heatsources to a selected section of the formation; providing at least oneoperating parameter of the in situ process to the computer system; usingat least one parameter with a simulation method and the computer systemto provide assessed information about the in situ process; and using theassessed information to operate the in situ process.
 5796. The method ofclaim 5795, further comprising providing the assessed information to acomputer system used for controlling the in situ process.
 5797. Themethod of claim 5795, wherein the computer system is remote from the insitu process.
 5798. The method of claim 5795, wherein the computersystem is located at or near the in situ process.
 5799. The method ofclaim 5795, wherein using the assessed information to operate the insitu process comprises: modifying at least one operating parameter; andoperating the in situ process with at least one modified operatingparameter.
 5800. A method of using a computer system for operating an insitu process for treating an oil shale formation, comprising operatingthe in situ process using one or more operating parameters, wherein thein situ process comprises providing heat from one or more heat sourcesto at least one portion of the formation, and wherein the in situprocess comprises allowing the heat to transfer from the one or moreheat sources to a selected section of the formation; providing at leastone operating parameter of the in situ process to the computer system;using at least one parameter with a first simulation method and thecomputer system to provide assessed information about the in situprocess; and obtaining information from a second simulation method andthe computer system using the assessed information and a desiredparameter.
 5801. The method of claim 5800, further comprising using theobtained information to operate the in situ process.
 5802. The method ofclaim 5800, wherein the first simulation method is the same as thesecond simulation method.
 5803. The method of claim 5800, furthercomprising providing the obtained information to a computer system usedfor controlling the in situ process.
 5804. The method of claim 5800,wherein using the obtained information to operate the in situ processcomprises: modifying at least one operating parameter; and operating thein situ process with at least one modified operating parameter. 5805.The method of claim 5800, wherein the obtained information comprises atleast one operating parameter for use in the in situ process thatachieves the desired parameter.
 5806. The method of claim 5800, whereinthe computer system is remote from the in situ process.
 5807. The methodof claim 5800, wherein the computer system is located at or near the insitu process.
 5808. The method of claim 5800, wherein the desiredparameter comprises a selected gas to oil ratio.
 5809. The method ofclaim 5800, wherein the desired parameter comprises a selectedproduction rate of fluid produced from the formation.
 5810. The methodof claim 5800, wherein the desired parameter comprises a selectedproduction rate of fluid at a selected time produced from the formation.5811. The method of claim 5800, wherein the desired parameter comprisesa selected olefin content of produced fluids.
 5812. The method of claim5800, wherein the desired parameter comprises a selected carbon numberdistribution of produced fluids.
 5813. The method of claim 5800, whereinthe desired parameter comprises a selected ethene to ethane ratio ofproduced fluids.
 5814. The method of claim 5800, wherein the desiredparameter comprises a desired atomic carbon to hydrogen ratio ofproduced fluids.
 5815. The method of claim 5800, wherein the desiredparameter comprises a selected gas to oil ratio of produced fluids.5816. The method of claim 5800, wherein the desired parameter comprisesa selected pressure in the formation.
 5817. The method of claim 5800,wherein the desired parameter comprises a selected total mass recoveryfrom the formation.
 5818. The method of claim 5800, wherein the desiredparameter comprises a selected production rate of fluid produced fromthe formation.
 5819. A system, comprising: a CPU; a data memory coupledto the CPU; and a system memory coupled to the CPU, wherein the systemmemory is configured to store one or more computer programs executableby the CPU, and wherein the computer programs are executable toimplement a method of using a computer system for operating an in situprocess for treating an oil shale formation, comprising: operating thein situ process using one or more operating parameters, wherein the insitu process comprises providing heat from one or more heat sources toat least one portion of the formation, and wherein the in situ processcomprises allowing the heat to transfer from the one or more heatsources to a selected section of the formation; providing at least oneoperating parameter of the in situ process to the computer system; andusing at least one parameter with a simulation method and the computersystem to provide assessed information about the in situ process. 5820.A carrier medium comprising program instructions, wherein the programinstructions are computer-executable to implement a method comprising:operating the in situ process using one or more operating parameters,wherein the in situ process comprises providing heat from one or moreheat sources to at least one portion of the formation, and wherein thein situ process comprises allowing the heat to transfer from the one ormore heat sources to a selected section of the formation; providing atleast one operating parameter of the in situ process to the computersystem; and using at least one parameter with a simulation method andthe computer system to provide assessed information about the in situprocess.
 5821. A system, comprising: a CPU; a data memory coupled to theCPU; and a system memory coupled to the CPU, wherein the system memoryis configured to store one or more computer programs executable by theCPU, and wherein the computer programs are executable to implement amethod of using a computer system for operating an in situ process fortreating an oil shale formation, comprising: operating the in situprocess using one or more operating parameters, wherein the in situprocess comprises providing heat from one or more heat sources to atleast one portion of the formation, and wherein the in situ processcomprises allowing the heat to transfer from the one or more heatsources to a selected section of the formation; providing at least oneoperating parameter of the in situ process to the computer system; usingat least one parameter with a simulation method and the computer systemto provide assessed information about the in situ process; and using theassessed information to operate the in situ process.
 5822. A carriermedium comprising program instructions, wherein the program instructionsare computer-executable to implement a method comprising: operating thein situ process using one or more operating parameters, wherein the insitu process comprises providing heat from one or more heat sources toat least one portion of the formation, and wherein the in situ processcomprises allowing the heat to transfer from the one or more heatsources to a selected section of the formation; providing at least oneoperating parameter of the in situ process to the computer system; usingat least one parameter with a simulation method and the computer systemto provide assessed information about the in situ process; and using theassessed information to operate the in situ process.
 5823. A system,comprising: a CPU; a data memory coupled to the CPU; and a system memorycoupled to the CPU, wherein the system memory is configured to store oneor more computer programs executable by the CPU, and wherein thecomputer programs are executable to implement a method of using acomputer system for operating an in situ process for treating an oilshale formation, comprising: operating the in situ process using one ormore operating parameters, wherein the in situ process comprisesproviding heat from one or more heat sources to at least one portion ofthe formation, and wherein the in situ process comprises allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation; providing at least one operating parameter of the insitu process to the computer system; using at least one parameter with afirst simulation method and the computer system to provide assessedinformation about the in situ process; and obtaining information from asecond simulation method and the computer system using the assessedinformation and a desired parameter.
 5824. A carrier medium comprisingprogram instructions, wherein the program instructions arecomputer-executable to implement a method comprising: operating the insitu process using one or more operating parameters, wherein the in situprocess comprises providing heat from one or more heat sources to atleast one portion of the formation, and wherein the in situ processcomprises allowing the heat to transfer from the one or more heatsources to a selected section of the formation; providing at least oneoperating parameter of the in situ process to the computer system; usingat least one parameter with a first simulation method and the computersystem to provide assessed information about the in situ process; andobtaining information from a second simulation method and the computersystem using the assessed information and a desired parameter.
 5825. Amethod of modeling one or more stages of a process for treating an oilshale formation in situ with a simulation method using a computersystem, comprising: providing at least one property of the formation tothe computer system; providing at least one operating condition for theone or more stages of the in situ process to the computer system,wherein the in situ process comprises providing heat from one or moreheat sources to at least one portion of the formation, and wherein thein situ process comprises allowing the heat to transfer from the one ormore heat sources to a selected section of the formation; assessing atleast one process characteristic of the one or more stages using thesimulation method.
 5826. The method of claim 5825, wherein thesimulation method is a body-fitted finite difference simulation method.5827. The method of claim 5825, wherein the simulation method is areservoir simulation method.
 5828. The method of claim 5825, wherein thesimulation method is a space-fitted finite difference simulation method.5829. The method of claim 5825, wherein the simulation method simulatesheating of the formation.
 5830. The method of claim 5825, wherein thesimulation method simulates fluid flow in the formation.
 5831. Themethod of claim 5825, wherein the simulation method simulates masstransfer in the formation.
 5832. The method of claim 5825, wherein thesimulation method simulates heat transfer in the formation.
 5833. Themethod of claim 5825, wherein the simulation method simulates chemicalreactions in the one or more stages of the process in the formation.5834. The method of claim 5825, wherein the simulation method simulatesremoval of contaminants from the formation.
 5835. The method of claim5825, wherein the simulation method simulates recovery of heat from theformation.
 5836. The method of claim 5825, wherein the simulation methodsimulates injection of fluids into the formation.
 5837. The method ofclaim 5825, wherein the one or more stages comprise heating of theformation.
 5838. The method of claim 5825, wherein the one or morestages comprise generation of pyrolyzation fluids.
 5839. The method ofclaim 5825, wherein the one or more stages comprise remediation of theformation.
 5840. The method of claim 5825, wherein the one or morestages comprise shut-in of the formation.
 5841. The method of claim5825, wherein at least one operating condition of a remediation stage isthe flow rate of ground water into the formation.
 5842. The method ofclaim 5825, wherein at least one operating condition of a remediationstage is the flow rate of injected fluids into the formation.
 5843. Themethod of claim 5825, wherein at least one process characteristic of aremediation stage is the concentration of contaminants in the formation.5844. The method of claim 5825, further comprising: providing to thecomputer system at least one set of operating conditions for at leastone of the stages of the in situ process, wherein the in situ processcomprises providing heat from one or more heat sources to at least oneportion of the formation, and wherein the in situ process comprisesallowing the heat to transfer from the one or more heat sources to aselected section of the formation; providing to the computer system atleast one desired process characteristic for at least one of the stagesof the in situ process; and assessing at least one additional operatingcondition for at least one of the stages that achieves at least onedesired process characteristic for at least one of the stages.
 5845. Amethod of using a computer system for modeling an in situ process fortreating an oil shale formation, comprising: providing at least oneproperty of the formation to a computer system; providing at least oneoperating condition to the computer system; assessing at least oneprocess characteristic of the in situ process, wherein the in situprocess comprises providing heat from one or more heat sources to atleast one portion of the formation, and wherein the in situ processcomprises allowing the heat to transfer from the one or more heatsources to a selected section of the formation; and assessing at leastone deformation characteristic of the formation using a simulationmethod from at least one property, at least one operating condition, andat least one process characteristic.
 5846. The method of claim 5845,wherein the in situ process comprises two or more heat sources. 5847.The method of claim 5845, wherein the in situ process provides heat fromone or more heat sources to at least one portion of the formation. 5848.The method of claim 5845, wherein the simulation method comprises afinite element simulation method.
 5849. The method of claim 5845,wherein the formation comprises a treated portion and an untreatedportion.
 5850. The method of claim 5845, wherein at least onedeformation characteristic comprises subsidence.
 5851. The method ofclaim 5845, wherein at least one deformation characteristic comprisesheave.
 5852. The method of claim 5845, wherein at least one deformationcharacteristic comprises compaction.
 5853. The method of claim 5845,wherein at least one deformation characteristic comprises sheardeformation.
 5854. The method of claim 5845, wherein at least oneoperating condition comprises a pressure.
 5855. The method of claim5845, wherein at least one operating condition comprises a temperature.5856. The method of claim 5845, wherein at least one operating conditioncomprises a process time.
 5857. The method of claim 5845, wherein atleast one operating condition comprises a rate of pressure increase.5858. The method of claim 5845, wherein at least one operating conditioncomprises a heating rate.
 5859. The method of claim 5845, wherein atleast one operating condition comprises a width of a treated portion ofthe formation.
 5860. The method of claim 5845, wherein at least oneoperating condition comprises a thickness of a treated portion of theformation.
 5861. The method of claim 5845, wherein at least oneoperating condition comprises a thickness of an overburden of theformation.
 5862. The method of claim 5845, wherein at least one processcharacteristic comprises a pore pressure distribution in the formation.5863. The method of claim 5845, wherein at least one processcharacteristic comprises a temperature distribution in the formation.5864. The method of claim 5845, wherein at least one processcharacteristic comprises a heat input rate.
 5865. The method of claim5845, wherein at least one property comprises a physical property of theformation.
 5866. The method of claim 5845, wherein at least one propertycomprises richness of the formation.
 5867. The method of claim 5845,wherein at least one property comprises a heat capacity.
 5868. Themethod of claim 5845, wherein at least one property comprises a thermalconductivity.
 5869. The method of claim 5845, wherein at least oneproperty comprises a coefficient of thermal expansion.
 5870. The methodof claim 5845, wherein at least one property comprises a mechanicalproperty.
 5871. The method of claim 5845, wherein at least one propertycomprises an elastic modulus.
 5872. The method of claim 5845, wherein atleast one property comprises a Poisson's ratio.
 5873. The method ofclaim 5845, wherein at least one property comprises cohesion stress.5874. The method of claim 5845, wherein at least one property comprisesa friction angle.
 5875. The method of claim 5845, wherein at least oneproperty comprises a cap eccentricity.
 5876. The method of claim 5845,wherein at least one property comprises a cap yield stress.
 5877. Themethod of claim 5845, wherein at least one property comprises a cohesioncreep multiplier.
 5878. The method of claim 5845, wherein at least oneproperty comprises a thermal expansion coefficient.
 5879. A method ofusing a computer system for modeling an in situ process for treating anoil shale formation, comprising: providing to the computer system atleast one set of operating conditions for the in situ process, whereinthe process comprises providing heat from one or more heat sources to atleast one portion of the formation, and wherein the process comprisesallowing the heat to transfer from the one or more heat sources to aselected section of the formation; providing to the computer system atleast one desired deformation characteristic for the in situ process;and assessing at least one additional operating condition of theformation that achieves at least one desired deformation characteristic.5880. The method of claim 5879, further comprising operating the in situsystem using at least one additional operating condition.
 5881. Themethod of claim 5879, wherein the in situ process comprises two or moreheat sources.
 5882. The method of claim 5879, wherein the in situprocess provides heat from one or more heat sources to at least oneportion of the formation.
 5883. The method of claim 5879, wherein the insitu process allows heat to transfer from one or more heat sources to aselected section of the formation.
 5884. The method of claim 5879,wherein at least one set of operating conditions comprises at least oneset of pressures.
 5885. The method of claim 5879, wherein at least oneset of operating conditions comprises at least one set of temperatures.5886. The method of claim 5879, wherein at least one set of operatingconditions comprises at least one set of heating rates.
 5887. The methodof claim 5879, wherein at least one set of operating conditionscomprises at least one set of overburden thicknesses.
 5888. The methodof claim 5879, wherein at least one set of operating conditionscomprises at least one set of thicknesses of a treated portion of theformation.
 5889. The method of claim 5879, wherein at least one set ofoperating conditions comprises at least one set of widths of a treatedportion of the formation.
 5890. The method of claim 5879, wherein atleast one set of operating conditions comprises at least one set ofradii of a treated portion of the formation.
 5891. The method of claim5879, wherein at least one desired deformation characteristic comprisesa selected subsidence.
 5892. The method of claim 5879, wherein at leastone desired deformation characteristic comprises a selected heave. 5893.The method of claim 5879, wherein at least one desired deformationcharacteristic comprises a selected compaction.
 5894. The method ofclaim 5879, wherein at least one desired deformation characteristiccomprises a selected shear deformation.
 5895. A method of using acomputer system for modeling an in situ process for treating an oilshale formation, comprising: providing one or more values of at leastone operating condition; assessing one or more values of at least onedeformation characteristic using a simulation method based on the one ormore values of at least one operating condition; providing a desiredvalue of at least one deformation characteristic for the in situ processto the computer system, wherein the process comprises providing heatfrom one or more heat sources to at least one portion of the formation,and wherein the process comprises allowing the heat to transfer from theone or more heat sources to a selected section of the formation; andassessing a desired value of at least one operating condition thatachieves the desired value of at least one deformation characteristicfrom the determined values of at least one deformation characteristicand the provided values of at least one operating condition.
 5896. Themethod of claim 5895, further comprising operating the in situ processusing the desired value of at least one operating condition.
 5897. Themethod of claim 5895, wherein the in situ process comprises two or moreheat sources.
 5898. The method of claim 5895, wherein at least oneoperating condition comprises a pressure.
 5899. The method of claim5895, wherein at least one operating condition comprises a heat inputrate.
 5900. The method of claim 5895, wherein at least one operatingcondition comprises a temperature.
 5901. The method of claim 5895,wherein at least one operating condition comprises a heating rate. 5902.The method of claim 5895, wherein at least one operating conditioncomprises an overburden thickness.
 5903. The method of claim 5895,wherein at least one operating condition comprises a thickness of atreated portion of the formation.
 5904. The method of claim 5895,wherein at least one operating condition comprises a width of a treatedportion of the formation.
 5905. The method of claim 5895, wherein atleast one operating condition comprises a radius of a treated portion ofthe formation.
 5906. The method of claim 5895, wherein at least onedeformation characteristic comprises subsidence.
 5907. The method ofclaim 5895, wherein at least one deformation characteristic comprisesheave.
 5908. The method of claim 5895, wherein at least one deformationcharacteristic comprises compaction.
 5909. The method of claim 5895,wherein at least one deformation characteristic comprises sheardeformation.
 5910. The method of claim 5895, wherein a value of at leastone formation characteristic comprises the formation characteristic as afunction of time.
 5911. The method of claim 5895, further comprisingdetermining a value of at least one deformation characteristic based onthe desired value of at least one operating condition using thesimulation method.
 5912. The method of claim 5895, wherein determiningthe desired value of at least one operating condition comprisesinterpolating the desired value from the determined values of at leastone formation characteristic and the provided values of at least oneoperating condition.
 5913. A method of using a computer system formodeling an in situ process for treating an oil shale formation,comprising: providing a desired value of at least one deformationcharacteristic for the in situ process to the computer system, whereinthe in situ process comprises providing heat from one or more heatsources to at least one portion of the formation, and wherein the insitu process comprises allowing the heat to transfer from the one ormore heat sources to a selected section of the formation; and assessinga value of at least one operating condition to achieve the desired valueof at least one deformation characteristic from a database in memory onthe computer system comprising a relationship between at least onedeformation characteristic and at least one operating condition for thein situ process.
 5914. The method of claim 5913, further comprisingoperating the in situ system using the desired value of at least oneoperating condition.
 5915. The method of claim 5913, wherein the in situsystem comprises two or more heat sources.
 5916. The method of claim5913, wherein the relationship is determined from one or moresimulations of the in situ process using a simulation method.
 5917. Themethod of claim 5913, wherein the relationship comprises one or morevalues of at least one deformation characteristic and correspondingvalues of at least one operating condition.
 5918. The method of claim5913, wherein the relationship comprises an analytical function. 5919.The method of claim 5913, wherein determining a value of at least oneoperating condition comprises interpolating a value of at least oneoperating condition from the relationship.
 5920. A system, comprising: aCPU; a data memory coupled to the CPU; and a system memory coupled tothe CPU, wherein the system memory is configured to store one or morecomputer programs executable by the CPU, and wherein the computerprograms are executable to implement a method of using a computer systemfor modeling an in situ process for treating an oil shale formation, themethod comprising: providing at least one property of the formation to acomputer system; providing at least one operating condition to thecomputer system; determining at least one process characteristic of thein situ process, wherein the process comprises providing heat from oneor more heat sources to at least one portion of the formation, andwherein the process comprises allowing the heat to transfer from the oneor more heat sources to a selected section of the formation; anddetermining at least one deformation characteristic of the formationusing a simulation method from at least one property, at least oneoperating condition, and at least one process characteristic.
 5921. Acarrier medium comprising program instructions, wherein the programinstructions are computer-executable to implement a method comprising:providing at least one property of the formation to a computer system;providing at least one operating condition to the computer system;determining at least one process characteristic of the in situ process,wherein the process comprises providing heat from one or more heatsources to at least one portion of the formation, and wherein theprocess comprises allowing the heat to transfer from the one or moreheat sources to a selected section of the formation; and determining atleast one deformation characteristic of the formation using a simulationmethod from at least one property, at least one operating condition, andat least one process characteristic.
 5922. A system, comprising: a CPU;a data memory coupled to the CPU; and a system memory coupled to theCPU, wherein the system memory is configured to store one or morecomputer programs executable by the CPU, and wherein the computerprograms are executable to implement a method of using a computer systemfor modeling an in situ process for treating an oil shale formation, themethod comprising: providing to the computer system at least one set ofoperating conditions for the in situ process, wherein the processcomprises providing heat from one or more heat sources to at least oneportion of the formation, and wherein the process comprises allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation; providing to the computer system at least one desireddeformation characteristic for the in situ process; and determining atleast one additional operating condition of the formation that achievesat least one desired deformation characteristic.
 5923. A carrier mediumcomprising program instructions, wherein the program instructions arecomputer-executable to implement a method comprising: providing to thecomputer system at least one set of operating conditions for the in situprocess, wherein the process comprises providing heat from one or moreheat sources to at least one portion of the formation, and wherein theprocess comprises allowing the heat to transfer from the one or moreheat sources to a selected section of the formation; providing to thecomputer system at least one desired deformation characteristic for thein situ process; and determining at least one additional operatingcondition of the formation that achieves at least one desireddeformation characteristic.
 5924. A system, comprising: a CPU; a datamemory coupled to the CPU; and a system memory coupled to the CPU,wherein the system memory is configured to store one or more computerprograms executable by the CPU, and wherein the computer programs areexecutable to implement a method of using a computer system for modelingan in situ process for treating an oil shale formation, the methodcomprising: providing one or more values of at least one operatingcondition; determining one or more values of at least one deformationcharacteristic using a simulation method based on the one or more valuesof at least one operating condition; providing a desired value of atleast one deformation characteristic for the in situ process to thecomputer system, wherein the process comprises providing heat from oneor more heat sources to at least one portion of the formation, andwherein the process comprises allowing the heat to transfer from the oneor more heat sources to a selected section of the formation; anddetermining a desired value of at least one operating condition thatachieves the desired value of at least one deformation characteristicfrom the determined values of at least one deformation characteristicand the provided values of at least one operating condition.
 5925. Acarrier medium comprising program instructions, wherein the programinstructions are computer-executable to implement a method comprising:providing one or more values of at least one operating condition;determining one or more values of at least one deformationcharacteristic using a simulation method based on the one or more valuesof at least one operating condition; providing a desired value of atleast one deformation characteristic for the in situ process to thecomputer system, wherein the process comprises providing heat from oneor more heat sources to at least one portion of the formation, andwherein the process comprises allowing the heat to transfer from the oneor more heat sources to a selected section of the formation; anddetermining a desired value of at least one operating condition thatachieves the desired value of at least one deformation characteristicfrom the determined values of at least one deformation characteristicand the provided values of at least one operating condition.
 5926. Asystem, comprising: a CPU; a data memory coupled to the CPU; and asystem memory coupled to the CPU, wherein the system memory isconfigured to store one or more computer programs executable by the CPU,and wherein the computer programs are executable to implement a methodof using a computer system for modeling an in situ process for treatingan oil shale formation, the method comprising: providing a desired valueof at least one deformation characteristic for the in situ process tothe computer system, wherein the process comprises providing heat fromone or more heat sources to at least one portion of the formation, andwherein the process comprises allowing the heat to transfer from the oneor more heat sources to a selected section of the formation; anddetermining a value of at least one operating condition to achieve thedesired value of at least one deformation characteristic from a databasein memory on the computer system comprising a relationship between atleast one formation characteristic and at least one operating conditionfor the in situ process.
 5927. A carrier medium comprising programinstructions, wherein the program instructions are computer-executableto implement a method comprising: providing a desired value of at leastone deformation characteristic for the in situ process to the computersystem, wherein the process comprises providing heat from one or moreheat sources to at least one portion of the formation, and wherein theprocess comprises allowing the heat to transfer from the one or moreheat sources to a selected section of the formation; and determining avalue of at least one operating condition to achieve the desired valueof at least one deformation characteristic from a database in memory onthe computer system comprising a relationship between at least oneformation characteristic and at least one operating condition for the insitu process.
 5928. A system configurable to provide heat to an oilshale formation, comprising: a first oxidizer configurable to be placedin an opening in the formation, wherein the first oxidizer isconfigurable to oxidize a first fuel during use; a second oxidizerconfigurable to be placed in the opening, wherein the second oxidizer isconfigurable to oxidize a second fuel during use; and wherein the systemis configurable to allow heat from oxidation of the first fuel or thesecond fuel to transfer to the formation during use.
 5929. The system ofclaim 5928, wherein the system is configured to provide heat to the oilshale formation.
 5930. The system of claim 5928, wherein the firstoxidizer is configured to be placed in an opening in the formation andwherein the first oxidizer is configured to oxidize the first fuelduring use.
 5931. The system of claim 5928, wherein the second oxidizeris configured to be placed in the opening and wherein the secondoxidizer is configured to oxidize the second fuel during use.
 5932. Thesystem of claim 5928, wherein the system is configured to allow the heatfrom the oxidation to transfer to the formation during use.
 5933. Thesystem of claim 5928, wherein the first oxidizer comprises a burner.5934. The system of claim 5928, wherein the first oxidizer comprises aninline burner.
 5935. The system of claim 5928, wherein the secondoxidizer comprises a burner.
 5936. The system of claim 5928, wherein thesecond oxidizer comprises a ring burner.
 5937. The system of claim 5928,wherein a distance between the first oxidizer and the second oxidizer isless than about 250 meters.
 5938. The system of claim 5928, furthercomprising a conduit configurable to be placed in the opening.
 5939. Thesystem of claim 5928, further comprising a conduit configurable to beplaced in the opening, wherein the conduit is configurable to provide anoxidizing fluid to the first oxidizer during use.
 5940. The system ofclaim 5928, further comprising a conduit configurable to be placed inthe opening, wherein the conduit is configurable to provide the firstfuel to the first oxidizer during use.
 5941. The system of claim 5928,further comprising a conduit configurable to be placed in the opening,wherein the conduit is configurable to provide an oxidizing fluid to thesecond oxidizer during use.
 5942. The system of claim 5928, furthercomprising a conduit configurable to be placed in the opening, whereinthe conduit is configurable to provide the second fuel to the secondoxidizer during use.
 5943. The system of claim 5928, further comprisinga third oxidizer configurable to be placed in the opening, wherein thethird oxidizer is configurable to oxidize a third fuel during use. 5944.The system of claim 5928, further comprising a fuel source, wherein thefuel source is configurable to provide the first fuel to the firstoxidizer or the second fuel to the second oxidizer during use.
 5945. Thesystem of claim 5928, wherein the first fuel is different from thesecond fuel.
 5946. The system of claim 5928, wherein the first fuel isdifferent from the second fuel, wherein the second fuel compriseshydrogen.
 5947. The system of claim 5928, wherein a flow of the firstfuel is separately controlled from a flow of the second fuel.
 5948. Thesystem of claim 5928, wherein the first oxidizer is configurable to beplaced proximate an upper portion of the opening.
 5949. The system ofclaim 5928, wherein the second oxidizer is configurable to be placedproximate a lower portion of the opening.
 5950. The system of claim5928, further comprising insulation configurable to be placed proximatethe first oxidizer.
 5951. The system of claim 5928, further comprisinginsulation configurable to be placed proximate the second oxidizer.5952. The system of claim 5928, wherein products from oxidation of thefirst fuel or the second fuel are removed from the formation through theopening during use.
 5953. The system of claim 5928, further comprisingan exhaust conduit configurable to be coupled to the opening to allowexhaust fluid to flow from the formation through the exhaust conduitduring use.
 5954. The system of claim 5928, wherein the system isconfigured to allow the heat from the oxidation of the first fuel or thesecond fuel to transfer to the formation during use.
 5955. The system ofclaim 5928, wherein the system is configured to allow the heat from theoxidation to transfer to a pyrolysis zone in the formation during use.5956. The system of claim 5928, wherein the system is configured toallow the heat from the oxidation to transfer to a pyrolysis zone in theformation during use, and wherein the transferred heat causes pyrolysisof at least some hydrocarbons in the pyrolysis zone during use. 5957.The system of claim 5928, wherein at least some of the heat from theoxidation is generated at the first oxidizer.
 5958. The system of claim5928, wherein at least some of the heat from the oxidation is generatedat the second oxidizer
 5959. The system of claim 5928, wherein acombination of heat from the first oxidizer and heat from the secondoxidizer substantially uniformly heats a portion of the formation duringuse.
 5960. The system of claim 5928, further comprising a first conduitconfigurable to be placed in the opening of the formation, wherein thefirst conduit is configurable to provide a first oxidizing fluid to thefirst oxidizer in the opening during use, and wherein the first conduitis further configurable to provide a second oxidizing fluid to thesecond oxidizer in the opening during use.
 5961. The system of claim5960, further comprising a fuel conduit configurable to be placed in theopening, wherein the fuel conduit is further configurable to provide thefirst fuel to the first oxidizer during use.
 5962. The system of claim5961, wherein the fuel conduit is further configurable to be placed inthe first conduit.
 5963. The system of claim 5961, wherein the firstconduit is further configurable to be placed in the fuel conduit. 5964.The system of claim 5960, further comprising a fuel conduit configurableto be placed in the opening, wherein the fuel conduit is furtherconfigurable to provide the second fuel to the second oxidizer duringuse.
 5965. The system of claim 5960, wherein the first conduit isfurther configurable to provide the first fuel to the first oxidizerduring use.
 5966. An in situ method for heating an oil shale formation,comprising: providing a first oxidizing fluid to a first oxidizer placedin an opening in the formation; providing a first fuel to the firstoxidizer; oxidizing at least some of the first fuel in the firstoxidizer; providing a second oxidizing fluid to a second oxidizer placedin the opening in the formation; providing a second fuel to the secondoxidizer; oxidizing at least some of the second fuel in the secondoxidizer; and allowing heat from oxidation of the first fuel and thesecond fuel to transfer to a portion of the formation.
 5967. The methodof claim 5966, wherein the first oxidizing fluid is provided to thefirst oxidizer through a conduit placed in the opening.
 5968. The methodof claim 5966, wherein the second oxidizing fluid is provided to thesecond oxidizer through a conduit placed in the opening.
 5969. Themethod of claim 5966, wherein the first fuel is provided to the firstoxidizer through a conduit placed in the opening.
 5970. The method ofclaim 5966, wherein the first fuel is provided to the second oxidizerthrough a conduit placed in the opening.
 5971. The method of claim 5966,wherein the first oxidizing fluid and the first fuel are provided to thefirst oxidizer through a conduit placed in the opening.
 5972. The methodof claim 5966, further comprising using exhaust fluid from the firstoxidizer as a portion of the second fuel used in the second oxidizer.5973. The method of claim 5966, further comprising allowing the heat totransfer substantially by conduction from the portion of the formationto a pyrolysis zone of the formation.
 5974. The method of claim 5966,further comprising initiating oxidation of the second fuel in the secondoxidizer with an ignition source.
 5975. The method of claim 5966,further comprising removing exhaust fluids through the opening. 5976.The method of claim 5966, further comprising removing exhaust fluidsthrough the opening, wherein the exhaust fluids comprise heat andallowing at least some heat in the exhaust fluids to transfer from theexhaust fluids to the first oxidizing fluid prior to oxidation in thefirst oxidizer.
 5977. The method of claim 5966, further comprisingremoving exhaust fluids comprising heat through the opening, allowing atleast some heat in the exhaust fluids to transfer from the exhaustfluids to the first oxidizing fluid prior to oxidation, and increasing athermal efficiency of heating the oil shale formation.
 5978. The methodof claim 5966, further comprising removing exhaust fluids through anexhaust conduit coupled to the opening.
 5979. The method of claim 5966,further comprising removing exhaust fluids through an exhaust conduitcoupled to the opening and providing at least a portion of the exhaustfluids to a fourth oxidizer to be used as a fourth fuel in a fourthoxidizer, wherein the fourth oxidizer is located in a separate openingin the formation.
 5980. A system configurable to provide heat to an oilshale formation, comprising: an opening placed in the formation, whereinthe opening comprises a first elongated portion, a second elongatedportion, and a third elongated portion, wherein the second elongatedportion diverges from the first elongated portion in a first direction,wherein the third elongated portion diverges from the first elongatedportion in a second direction, and wherein the first direction issubstantially different than the second direction; a first heaterconfigurable to be placed in the second elongated portion, wherein thefirst heater is configurable to heat at least a portion of the formationduring use; a second heater configurable to be placed in the thirdelongated portion, wherein the second heater is configurable to heat toat least a portion of the formation during use; and wherein the systemis configurable to allow heat to transfer to the formation during use.5981. The system of claim 5980, wherein the first heater and the secondheater are configurable to heat to at least a portion of the formationduring use.
 5982. The system of claim 5980, wherein the second and thethird elongated portions are oriented substantially horizontally withinthe formation.
 5983. The system of claim 5980, wherein the firstdirection is about 180° opposite the second direction.
 5984. The systemof claim 5980, wherein the first elongated portion is placedsubstantially within an overburden of the formation.
 5985. The system ofclaim 5980, wherein the transferred heat substantially uniformly heats aportion of the formation during use.
 5986. The system of claim 5980,wherein the first heater or the second heater comprises a downholecombustor.
 5987. The system of claim 5980, wherein the first heater orthe second heater comprises an insulated conductor heater.
 5988. Thesystem of claim 5980, wherein the first heater or the second heatercomprises a conductor-in-conduit heater.
 5989. The system of claim 5980,wherein the first heater or the second heater comprises an elongatedmember heater.
 5990. The system of claim 5980, wherein the first heateror the second heater comprises a natural distributed combustor heater.5991. The system of claim 5980, wherein the first heater or the secondheater comprises a flameless distributed combustor heater.
 5992. Thesystem of claim 5980, wherein the first heater comprises a firstoxidizer and the second heater comprises a second oxidizer.
 5993. Thesystem of claim 5992, wherein the second elongated portion has a lengthof less than about 175 meters.
 5994. The system of claim 5992, whereinthe third elongated portion has a length of less than about 175 meters.5995. The system of claim 5992, further comprising a fuel conduitconfigurable to be placed in the opening, wherein the fuel conduit isfurther configurable to provide fuel to the first oxidizer during use.5996. The system of claim 5992, further comprising a fuel conduitconfigurable to be placed in the opening, wherein the fuel conduit isfurther configurable to provide fuel to the second oxidizer during use.5997. The system of claim 5992, further comprising a fuel source,wherein the fuel source is configurable to provide fuel to the firstoxidizer or the second oxidizer during use.
 5998. The system of claim5992, further comprising a third oxidizer placed within the firstelongated portion of the opening.
 5999. The system of claim 5998,further comprising a fuel conduit configurable to be placed in theopening, wherein the fuel conduit is further configurable to providefuel to the third oxidizer during use.
 6000. The system of claim 5998,further comprising a first fuel source configurable to provide a firstfuel to the first fuel conduit, a second fuel source configurable toprovide a second fuel to a second fuel conduit, and a third fuel sourceconfigurable to provide a third fuel to a third fuel conduit.
 6001. Thesystem of claim 6000, wherein the first fuel has a compositionsubstantially different from the second fuel or the third fuel. 6002.The system of claim 5980, further comprising insulation configurable tobe placed proximate the first heater.
 6003. The system of claim 5980,further comprising insulation configurable to be placed proximate thesecond heater.
 6004. The system of claim 5980, wherein a fuel isoxidized in the first heater or the second heater to generate heat andwherein products from oxidation are removed from the formation throughthe opening during use.
 6005. The system of claim 5980, wherein a fuelis oxidized in the first heater and the second heater and whereinproducts from oxidation are removed from the formation through theopening during use.
 6006. The system of claim 5980, further comprisingan exhaust conduit configurable to be coupled to the opening to allowexhaust fluid to flow from the formation through the exhaust conduitduring use.
 6007. The system of claim 5992, wherein the system isconfigured to allow the heat from oxidation of fuel to transfer to theformation during use.
 6008. The system of claim 5980, wherein the systemis configured to allow heat to transfer to a pyrolysis zone in theformation during use.
 6009. The system of claim 5980, wherein the systemis configured to allow heat to transfer to a pyrolysis zone in theformation during use, and wherein the transferred heat causes pyrolysisof at least some hydrocarbons within the pyrolysis zone during use.6010. The system of claim 5980, wherein a combination of the heatgenerated from the first heater and the heat generated from the secondheater substantially uniformly heats a portion of the formation duringuse.
 6011. The system of claim 5980, further comprising a third heaterplaced in the second elongated portion.
 6012. The system of claim 6011,wherein the third heater comprises a downhole combustor.
 6013. Thesystem of claim 6011, further comprising a fourth heater placed in thethird elongated portion.
 6014. The system of claim 6013, wherein thefourth heater comprises a downhole combustor.
 6015. The system of claim5980, wherein the first heater is configured to be placed in the secondelongated portion, wherein the first heater is configured to provideheat to at least a portion of the formation during use, wherein thesecond heater is configured to be placed in the third elongated portion,wherein the second heater is configured to provide heat to at least aportion of the formation during use, and wherein the system isconfigured to allow heat to transfer to the formation during use. 6016.The system of claim 5980, wherein the second and the third elongatedportions are located in a substantially similar plane.
 6017. The systemof claim 6016, wherein the opening comprises a fourth elongated portionand a fifth elongated portion, wherein the fourth elongated portiondiverges from the first elongated portion in a third direction, whereinthe fifth elongated portion diverges from the first elongated portion ina fourth direction, and wherein the third direction is substantiallydifferent than the fourth direction.
 6018. The system of claim 6017,wherein the fourth and fifth elongated portions are located in a planesubstantially different than the second and the third elongatedportions.
 6019. The system of claim 6017, wherein a third heater isconfigurable to be placed in the fourth elongated portion, and wherein afourth heater is configurable to be placed in the fifth elongatedportion.
 6020. An in situ method for heating an oil shale formation,comprising: providing heat from two or more heaters placed in an openingin the formation, wherein the opening comprises a first elongatedportion, a second elongated portion, and a third elongated portion,wherein the second elongated portion diverges from the first elongatedportion in a first direction, wherein the third elongated portiondiverges from the first elongated portion in a second direction, andwherein the first direction is substantially different than the seconddirection; allowing heat from the two or more heaters to transfer to aportion of the formation; and wherein the two or more heaters comprise afirst heater placed in the second elongated portion and a second heaterplaced in the third elongated portion.
 6021. The method of claim 6020,wherein the second and the third elongated portions are orientedsubstantially horizontally within the formation.
 6022. The method ofclaim 6020, wherein the first elongated portion is located substantiallywithin an overburden of the formation.
 6023. The method of claim 6020,further comprising substantially uniformly heating a portion of theformation.
 6024. The method of claim 6020, wherein the first heater orthe second heater comprises a downhole combustor.
 6025. The method ofclaim 6020, wherein the first heater or the second heater comprises aninsulated conductor heater.
 6026. The method of claim 6020, wherein thefirst heater or the second heater comprises a conductor-in-conduitheater.
 6027. The method of claim 6020, wherein the first heater or thesecond heater comprises an elongated member heater.
 6028. The method ofclaim 6020, wherein the first heater or the second heater comprises anatural distributed combustor heater.
 6029. The method of claim 6020,wherein the first heater or the second heater comprises a flamelessdistributed combustor heater.
 6030. The method of claim 6020, whereinthe first heater comprises a first oxidizer and the second heatercomprises a second oxidizer.
 6031. The method of claim 6020, wherein thefirst heater comprises a first oxidizer and the second heater comprisesa second oxidizer and further comprising providing fuel to the firstoxidizer through a fuel conduit placed in the opening.
 6032. The methodof claim 6020, wherein the first heater comprises a first oxidizer andthe second heater comprises a second oxidizer and further comprisingproviding fuel to the second oxidizer through a fuel conduit placed inthe opening.
 6033. The method of claim 6020, wherein the two or moreheaters comprise oxidizers and further comprising providing fuel to theoxidizers from a fuel source.
 6034. The method of claim 6030, furthercomprising providing heat to a portion of the formation using a thirdoxidizer placed within the first elongated portion of the opening. 6035.The method of claim 6020, wherein the first heater comprises a firstoxidizer and the second heater comprises a second oxidizer furthercomprising: providing heat to a portion of the formation using a thirdoxidizer placed within the first elongated portion of the opening; andproviding fuel to the third oxidizer through a fuel conduit placed inthe opening.
 6036. The method of claim 6020, wherein the two or moreheaters comprise oxidizers, and further comprising providing heat byoxidizing a fuel within the oxidizers and removing products of oxidationof fuel through the opening.
 6037. The method of claim 6020, wherein thetwo or more heaters comprise oxidizers, and further comprising removingproducts from oxidation of fuel through an exhaust conduit coupled tothe opening.
 6038. The method of claim 6020, further comprising allowingthe heat to transfer from the portion to a pyrolysis zone in theformation.
 6039. The method of claim 6020, further comprising allowingthe heat to transfer from the portion to a pyrolysis zone in theformation and pyrolyzing at least some hydrocarbons within the pyrolysiszone with the transferred heat.
 6040. The method of claim 6020, furthercomprising allowing the heat to transfer to from the portion to apyrolysis zone in the formation, pyrolyzing at least some hydrocarbonswithin the pyrolysis zone with the transferred heat, and producing aportion of the pyrolyzed hydrocarbons through a conduit placed in thefirst elongated portion.
 6041. The method of claim 6020, furthercomprising providing heat to a portion of the formation using a thirdheater placed in the second elongated portion.
 6042. The method of claim6041, wherein the third heater comprises a downhole combustor.
 6043. Themethod of claim 6041, further comprising providing heat to a portion ofthe formation using a fourth heater placed in the third elongatedportion.
 6044. The method of claim 6043, wherein the fourth heatercomprises a downhole combustor.
 6045. A system configurable to provideheat to an oil shale formation, comprising: an oxidizer configurable tobe placed in an opening in the formation, wherein the oxidizer isconfigurable to oxidize fuel to generate heat during use; a firstconduit configurable to be placed in the opening of the formation,wherein the first conduit is configurable to provide oxidizing fluid tothe oxidizer in the opening during use; a heater configurable to beplaced in the opening and configurable to provide additional heat; andwherein the system is configurable to allow the generated heat and theadditional heat to transfer to the formation during use.
 6046. Thesystem of claim 6045, wherein the heater comprises an insulatedconductor.
 6047. The system of claim 6045, wherein the heater comprisesa conductor-in-conduit heater.
 6048. The system of claim 6045, whereinthe heater comprises an elongated member heater.
 6049. The system ofclaim 6045, wherein the heater comprises a flameless distributedcombustor.
 6050. The system of claim 6045, wherein the oxidizer isconfigurable to be placed proximate an upper portion of the opening.6051. The system of claim 6045, further comprising insulationconfigurable to be placed proximate the oxidizer.
 6052. The system ofclaim 6045, wherein the heater is configurable to be coupled to thefirst conduit.
 6053. The system of claim 6045, wherein products from theoxidation of the fuel are removed from the formation through the openingduring use.
 6054. The system of claim 6045, further comprising anexhaust conduit configurable to be coupled to the opening to allowexhaust fluid to flow from the formation through the exhaust conduitduring use.
 6055. The system of claim 6045, wherein the system isconfigured to allow the generated heat and the additional heat totransfer to the formation during use.
 6056. The system of claim 6045,wherein the system is configured to allow the generated heat and theadditional heat to transfer to a pyrolysis zone in the formation duringuse.
 6057. The system of claim 6045, wherein the system is configured toallow the generated heat and the additional heat to transfer to apyrolysis zone in the formation during use, and wherein the transferredheat pyrolyzes of at least some hydrocarbons within the pyrolysis zoneduring use.
 6058. The system of claim 6045, wherein a combination of thegenerate heat and the additional heat substantially uniformly heats aportion of the formation during use.
 6059. The system of claim 6045,wherein the oxidizer is configured to be placed in the opening in theformation and wherein the oxidizer is configured to oxidize at leastsome fuel during use.
 6060. The system of claim 6045, wherein the firstconduit is configured to be placed in the opening of the formation andwherein the first conduit is configured to provide oxidizing fluid tothe oxidizer in the opening during use.
 6061. The system of claim 6045,wherein the heater is configured to be placed in the opening and whereinthe heater is configurable to provide heat to a portion of the formationduring use
 6062. The system of claim 6045, wherein the system isconfigured to allow the heat from the oxidation of at least some fueland from the heater to transfer to the formation during use.
 6063. An insitu method for heating an oil shale formation, comprising: allowingheat to transfer from a heater placed in an opening to a portion of theformation. providing oxidizing fluid to an oxidizer placed in theopening in the formation; providing fuel to the oxidizer; oxidizing atleast some fuel in the oxidizer; and allowing additional heat fromoxidation of at least some fuel to transfer to the portion of theformation.
 6064. The method of claim 6063, wherein the heater comprisesan insulated conductor.
 6065. The method of claim 6063, wherein theheater comprises a conductor-in-conduit heater.
 6066. The method ofclaim 6063, wherein the heater comprises an elongated member heater.6067. The method of claim 6063, wherein the heater comprises a flamelessdistributed combustor.
 6068. The method of claim 6063, wherein theoxidizer is placed proximate an upper portion of the opening.
 6069. Themethod of claim 6063, further comprising allowing the additional heat totransfer from the portion to a pyrolysis zone in the formation. 6070.The method of claim 6063, further comprising allowing the additionalheat to transfer from the portion to a pyrolysis zone in the formationand pyrolyzing at least some hydrocarbons within the pyrolysis zone.6071. The method of claim 6063, further comprising substantiallyuniformly heating the portion of the formation.
 6072. The method ofclaim 6063, further comprising removing exhaust fluids through theopening.
 6073. The method of claim 6063, further comprising removingexhaust fluids through an exhaust annulus in the formation.
 6074. Themethod of claim 6063, further comprising removing exhaust fluids throughan exhaust conduit coupled to the opening.
 6075. A system configurableto provide heat to an oil shale formation, comprising: a heaterconfigurable to be placed in an opening in the formation, wherein theheater is configurable to heat a portion of the formation to atemperature sufficient to sustain oxidation of hydrocarbons during use;an oxidizing fluid source configurable to provide an oxidizing fluid toa reaction zone of the formation to oxidize at least some hydrocarbonsin the reaction zone during use such that heat is generated in thereaction zone, and wherein at least some of the reaction zone has beenpreviously heated by the heater; a first conduit configurable to beplaced in the opening, wherein the first conduit is configurable toprovide the oxidizing fluid from the oxidizing fluid source to thereaction zone in the formation during use, wherein the flow of oxidizingfluid can be controlled along at least a segment of the first conduit;and wherein the system is configurable to allow the generated heat totransfer from the reaction zone to the formation during use.
 6076. Thesystem of claim 6075, wherein the system is configurable to providehydrogen to the reaction zone during use.
 6077. The system of claim6075, wherein the oxidizing fluid is transported through the reactionzone substantially by diffusion.
 6078. The system of claim 6075, whereinthe system is configurable to allow the generated heat to transfer fromthe reaction zone to a pyrolysis zone in the formation during use. 6079.The system of claim 6075, wherein the system is configurable to allowthe generated heat to transfer substantially by conduction from thereaction zone to the formation during use.
 6080. The system of claim6075, wherein a temperature within the reaction zone can be controlledalong at least a segment of the first conduit during use.
 6081. Thesystem of claim 6075, wherein a heating rate in at least a section ofthe formation proximate at least a segment of the first conduit becontrolled.
 6082. The system of claim 6075, wherein the oxidizing fluidis configurable to be transported through the reaction zonesubstantially by diffusion, and wherein a rate of diffusion of theoxidizing fluid can controlled by a temperature within the reactionzone.
 6083. The system of claim 6075, wherein the first conduitcomprises orifices, and wherein the orifices are configurable to providethe oxidizing fluid into the opening during use.
 6084. The system ofclaim 6075, wherein the first conduit comprises critical flow orifices,and wherein the critical flow orifices are positioned on the firstconduit such that a flow rate of the oxidizing fluid is controlled at aselected rate during use.
 6085. The system of claim 6075, furthercomprising a second conduit configurable to remove an oxidation productduring use.
 6086. The system of claim 6085, wherein the second conduitis further configurable to allow heat within the oxidation product totransfer to the oxidizing fluid in the first conduit during use. 6087.The system of claim 6085, wherein a pressure of the oxidizing fluid inthe first conduit and a pressure of the oxidation product in the secondconduit are controlled during use such that a concentration of theoxidizing fluid along the length of the first conduit is substantiallyuniform.
 6088. The system of claim 6085, wherein the oxidation productis substantially inhibited from flowing into portions of the formationbeyond the reaction zone during use.
 6089. The system of claim 6075,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone during use.
 6090. Thesystem of claim 6075, wherein the portion of the formation extendsradially from the opening a distance of less than approximately 3 m.6091. The system of claim 6075, wherein the reaction zone extendsradially from the opening a distance of less than approximately 3 m.6092. The system of claim 6075, wherein the system is configurable topyrolyze at least some hydrocarbons in a pyrolysis zone of theformation.
 6093. The system of claim 6075, wherein the heater isconfigured to be placed in an opening in the formation and wherein theheater is configured to provide the heat to at least the portion of theformation during use.
 6094. The system of claim 6075, wherein a firstconduit is configured to be placed in the opening and wherein the firstconduit is configured to provide the oxidizing fluid from the oxidizingfluid source to the reaction zone in the formation during use.
 6095. Thesystem of claim 6075, wherein the flow of oxidizing fluid is controlledalong at least a segment of the length of the first conduit and whereinthe system is configured to allow the additional heat to transfer fromthe reaction zone to the formation during use.
 6096. An in situ methodfor providing heat to an oil shale formation, comprising: heating aportion of the formation to a temperature sufficient to support reactionof hydrocarbons with an oxidizing fluid within the portion of theformation; providing the oxidizing fluid to a reaction zone in theformation; controlling a flow of the oxidizing fluid along at least alength of the reaction zone; generating heat within the reaction zone;and allowing the generated heat to transfer to the formation.
 6097. Themethod of claim 6096, further comprising allowing the oxidizing fluid toreact with at least some of the hydrocarbons in the reaction zone togenerate the heat in the reaction zone.
 6098. The method of claim 6096,wherein at least a section of the reaction zone is proximate an openingin the formation.
 6099. The method of claim 6096, further comprisingtransporting the oxidizing fluid through the reaction zone substantiallyby diffusion.
 6100. The method of claim 6096, further comprisingtransporting the oxidizing fluid through the reaction zone substantiallyby diffusion, and controlling a rate of diffusions of the oxidizingfluid by controlling a temperature within the reaction zone.
 6101. Themethod of claim 6096, wherein the generated heat transfers from thereaction zone to a pyrolysis zone in the formation.
 6102. The method ofclaim 6096, wherein the generated heat transfers from the reaction zoneto the formation substantially by conduction.
 6103. The method of claim6096, further comprising controlling a temperature along at least alength of the reaction zone.
 6104. The method of claim 6096, furthercomprising controlling a flow of the oxidizing fluid along at least alength of the reaction zone, and controlling a temperature along atleast a length of the reaction zone.
 6105. The method of claim 6096,further comprising controlling a heating rate along at least a length ofthe reaction zone.
 6106. The method of claim 6096, wherein the oxidizingfluid is provided through a conduit placed within an opening in theformation, wherein the conduit comprises orifices.
 6107. The method ofclaim 6096, further comprising controlling a rate of oxidation byproviding the oxidizing fluid to the reaction zone from a conduit havingcritical flow orifices.
 6108. The method of claim 6096, wherein theoxidizing fluid is provided to the reaction zone through a conduitplaced within the formation, and further comprising positioning criticalflow orifices on the conduit such that the flow rate of the oxidizingfluid to at least a length of the reaction zone is controlled at aselected flow rate.
 6109. The method of claim 6096, wherein theoxidizing fluid is provided to the reaction zone from a conduit placedwithin an opening in the formation, and further comprising sizingcritical flow orifices on the conduit such that the flow rate of theoxidizing fluid to at least a length of the reaction zone is controlledat a selected flow rate.
 6110. The method of claim 6096, furthercomprising increasing a volume of the reaction zone, and increasing theflow of the oxidizing fluid to the reaction zone such that a rate ofoxidation within the reaction zone is substantially constant over time.6111. The method of claim 6096, further comprising maintaining asubstantially constant rate of oxidation within the reaction zone overtime.
 6112. The method of claim 6096, wherein a conduit is placed in anopening in the formation, and further comprising cooling the conduitwith the oxidizing fluid to reduce heating of the conduit by oxidation.6113. The method of claim 6096, further comprising removing an oxidationproduct from the formation through a conduit placed in an opening in theformation.
 6114. The method of claim 6096, further comprising removingan oxidation product from the formation through a conduit placed in anopening in the formation and substantially inhibiting the oxidationproduct from flowing into a surrounding portion of the formation. 6115.The method of claim 6096, further comprising inhibiting the oxidizingfluid from flowing into a surrounding portion of the formation. 6116.The method of claim 6096, further comprising removing at least somewater from the formation prior to heating the portion.
 6117. The methodof claim 6096, further comprising providing additional heat to theformation from an electric heater placed in the opening.
 6118. Themethod of claim 6096, further comprising providing additional heat tothe formation from an electric heater placed in an opening in theformation such that the oxidizing fluid continuously oxidizes at least aportion of the hydrocarbons in the reaction zone.
 6119. The method ofclaim 6096, further comprising providing additional heat to theformation from an electric heater placed in the opening to maintain aconstant heat rate in the formation.
 6120. The method of claim 6119,further comprising providing electricity to the electric heater using awind powered device.
 6121. The method of claim 6119, further comprisingproviding electricity to the electric heater using a solar powereddevice.
 6122. The method of claim 6096, further comprising maintaining atemperature within the portion above about the temperature sufficient tosupport the reaction of hydrocarbons with the oxidizing fluid.
 6123. Themethod of claim 6096, further comprising providing additional heat tothe formation from an electric heater placed in the opening andcontrolling the additional heat such that a temperature of the portionis greater than about the temperature sufficient to support the reactionof hydrocarbons with the oxidizing fluid.
 6124. The method of claim6096, further comprising removing oxidation products from the formation,and generating electricity using oxidation products removed from theformation.
 6125. The method of claim 6096, further comprising removingoxidation products from the formation, and using at least some of theremoved oxidation products in an air compressor.
 6126. The method ofclaim 6096, further comprising increasing a flow of the oxidizing fluidin the opening to accommodate an increase in a volume of the reactionzone over time.
 6127. The method of claim 6096, further comprisingassessing a temperature in or proximate an opening in the formation,wherein the flow of oxidizing fluid along at least a section of thereaction zone is controlled as a function of the assessed temperature.6128. The method of claim 6096, further comprising assessing atemperature in or proximate an opening in the formation, and increasingthe flow of oxidizing fluid as the assessed temperature decreases. 6129.The method of claim 6096, further comprising controlling the flow ofoxidizing fluid to maintain a temperature in or proximate an opening inthe formation at a temperature less than a pre-selected temperature.6130. A system configurable to provide heat to an oil shale formation,comprising: a heater configurable to be placed in an opening in theformation, wherein the heater is configurable to provide heat to atleast a portion of the formation during use; an oxidizing fluid sourceconfigurable to provide an oxidizing fluid to a reaction zone of theformation to generate heat in the reaction zone during use, wherein atleast a portion of the reaction zone has been previously heated by theheater during use; a conduit configurable to be placed in the opening,wherein the conduit is configurable to provide the oxidizing fluid fromthe oxidizing fluid source to the reaction zone in the formation duringuse; wherein the system is configurable to provide molecular hydrogen tothe reaction zone during use; and wherein the system is configurable toallow the generated heat to transfer from the reaction zone to theformation during use.
 6131. The system of claim 6130, wherein the systemis configurable to allow the oxidizing fluid to be transported throughthe reaction zone substantially by diffusion during use.
 6132. Thesystem of claim 6130, wherein the system is configurable to allow thegenerated heat to transfer from the reaction zone to a pyrolysis zone inthe formation during use.
 6133. The system of claim 6130, wherein thesystem is configurable to allow the generated heat to transfersubstantially by conduction from the reaction zone to the formationduring use.
 6134. The system of claim 6130, wherein the flow ofoxidizing fluid can be controlled along at least a segment of theconduit such that a temperature can be controlled along at least asegment of the conduit during use.
 6135. The system of claim 6130,wherein a flow of oxidizing fluid can be controlled along at least asegment of the conduit such that a heating rate in at least a section ofthe formation can be controlled.
 6136. The system of claim 6130, whereinthe oxidizing fluid is configurable to move through the reaction zonesubstantially by diffusion during use, wherein a rate of diffusion cancontrolled by a temperature of the reaction zone.
 6137. The system ofclaim 6130, wherein the conduit comprises orifices, and wherein theorifices are configurable to provide the oxidizing fluid into theopening during use.
 6138. The system of claim 6130, wherein the conduitcomprises critical flow orifices, and wherein the critical flow orificesare configurable to control a flow of the oxidizing fluid such that arate of oxidation in the formation is controlled during use.
 6139. Thesystem of claim 6130, wherein the conduit comprises a first conduit anda second conduit, wherein the second conduit is configurable to removean oxidation product during use.
 6140. The system of claim 6130, whereinthe oxidizing fluid is substantially inhibited from flowing from thereaction zone into a surrounding portion of the formation.
 6141. Thesystem of claim 6130, wherein at least the portion of the formationextends radially from the opening a distance of less than approximately3 m.
 6142. The system of claim 6130, wherein the reaction zone extendsradially from the opening a distance of less than approximately 3 m.6143. The system of claim 6130, wherein the system is configurable toallow transferred heat to pyrolyze at least some hydrocarbons in apyrolysis zone of the formation.
 6144. The system of claim 6130, whereinthe heater is configured to be placed in an opening in the formation andwherein the heater is configured to provide heat to at least a portionof the formation during use.
 6145. The system of claim 6130, wherein theconduit is configured to be placed in the opening to provide at leastsome of the oxidizing fluid from the oxidizing fluid source to thereaction zone in the formation during use, and wherein the flow of atleast some of the oxidizing fluid can be controlled along at least asegment of the first conduit.
 6146. The system of claim 6130, whereinthe system is configured to allow heat to transfer from the reactionzone to the formation during use.
 6147. The system of claim 6130,wherein the heater is configured to be placed in an opening in theformation and wherein the heater is configured to provide heat to atleast a portion of the formation during use.
 6148. The system of claim6130, wherein the conduit is configured to be placed in the opening andwherein the conduit is configured to provide the oxidizing fluid fromthe oxidizing fluid source to the reaction zone in the formation duringuse.
 6149. The system of claim 6130, wherein the flow of oxidizing fluidcan be controlled along at least a segment of the conduit.
 6150. Thesystem of claim 6130, wherein the system is configured to allow heat totransfer from the reaction zone to the formation during use.
 6151. Thesystem of claim 6130, wherein at least some of the provided hydrogen isproduced in the pyrolysis zone during use.
 6152. The system of claim6130, wherein at least some of the provided hydrogen is produced in thereaction zone during use.
 6153. The system of claim 6130, wherein atleast some of the provided hydrogen is produced in at least the heatedportion of the formation during use.
 6154. The system of claim 6130,wherein the system is configurable to provide hydrogen to the reactionzone during use such that production of carbon dioxide in the reactionzone is inhibited.
 6155. An in situ method for heating an oil shaleformation, comprising: heating a portion of the formation to atemperature sufficient to support reaction of hydrocarbons within theportion of the formation with an oxidizing fluid; providing theoxidizing fluid to a reaction zone in the formation; allowing theoxidizing fluid to react with at least a portion of the hydrocarbons inthe reaction zone to generate heat in the reaction zone; providingmolecular hydrogen to the reaction zone; and transferring the generatedheat from the reaction zone to a pyrolysis zone in the formation. 6156.The method of claim 6155, further comprising producing the molecularhydrogen in the pyrolysis zone.
 6157. The method of claim 6155, furthercomprising producing the molecular hydrogen in the reaction zone. 6158.The method of claim 6155, further comprising producing the molecularhydrogen in at least the heated portion of the formation.
 6159. Themethod of claim 6155, further comprising inhibiting production of carbondioxide in the reaction zone.
 6160. The method of claim 6155, furthercomprising allowing the oxidizing fluid to transfer through the reactionzone substantially by diffusion.
 6161. The method of claim 6155, furthercomprising allowing the oxidizing fluid to transfer through the reactionzone by diffusion, wherein a rate of diffusion is controlled by atemperature of the reaction zone.
 6162. The method of claim 6155,wherein at least some of the generated heat transfers to the pyrolysiszone substantially by conduction.
 6163. The method of claim 6155,further comprising controlling a flow of the oxidizing fluid along atleast a segment reaction zone such that a temperature is controlledalong at least a segment of the reaction zone.
 6164. The method of claim6155, further comprising controlling a flow of the oxidizing fluid alongat least a segment of the reaction zone such that a heating rate iscontrolled along at least a segment of the reaction zone.
 6165. Themethod of claim 6155, further comprising allowing at least someoxidizing fluid to flow into the formation through orifices in a conduitplaced in an opening in the formation.
 6166. The method of claim 6155,further comprising controlling a flow of the oxidizing fluid into theformation using critical flow orifices on a conduit placed in theopening such that a rate of oxidation is controlled.
 6167. The method ofclaim 6155, further comprising controlling a flow of the oxidizing fluidinto the formation with a spacing of critical flow orifices on a conduitplaced in an opening in the formation.
 6168. The method of claim 6155,further comprising controlling a flow of the oxidizing fluid with adiameter of critical flow orifices in a conduit placed in an opening inthe formation.
 6169. The method of claim 6155, further comprisingincreasing a volume of the reaction zone, and increasing the flow of theoxidizing fluid to the reaction zone such that a rate of oxidationwithin the reaction zone is substantially constant over time
 6170. Themethod of claim 6155, wherein a conduit is placed in an opening in theformation, and further comprising cooling the conduit with the oxidizingfluid to reduce heating of the conduit by oxidation.
 6171. The method ofclaim 6155, further comprising removing an oxidation product from theformation through a conduit placed in an opening in the formation. 6172.The method of claim 6155, further comprising removing an oxidationproduct from the formation through a conduit placed in an opening in theformation and inhibiting the oxidation product from flowing into asurrounding portion of the formation beyond the reaction zone.
 6173. Themethod of claim 6155, further comprising inhibiting the oxidizing fluidfrom flowing into a surrounding portion of the formation beyond thereaction zone.
 6174. The method of claim 6155, further comprisingremoving at least some water from the formation prior to heating theportion.
 6175. The method of claim 6155, further comprising providingadditional heat to the formation from an electric heater placed in theopening.
 6176. The method of claim 6155, further comprising providingadditional heat to the formation from an electric heater placed in theopening and continuously oxidizing at least a portion of thehydrocarbons in the reaction zone.
 6177. The method of claim 6155,further comprising providing additional heat to the formation from anelectric heater placed in an opening in the formation and maintaining aconstant heat rate within the pyrolysis zone.
 6178. The method of claim6155, further comprising providing additional heat to the formation froman electric heater placed in the opening such that the oxidation of atleast a portion of the hydrocarbons does not burn out.
 6179. The methodof claim 6155, further comprising removing oxidation products from theformation and generating electricity using at least some oxidationproducts removed from the formation.
 6180. The method of claim 6155,further comprising removing oxidation products from the formation andusing at least some oxidation products removed from the formation in anair compressor.
 6181. The method of claim 6155, further comprisingincreasing a flow of the oxidizing fluid in the reaction zone toaccommodate an increase in a volume of the reaction zone over time.6182. The method of claim 6155, further comprising increasing a volumeof the reaction zone such that an amount of heat provided to theformation increases.
 6183. The method of claim 6155, further comprisingassessing a temperature in or proximate the opening, and controlling theflow of oxidizing fluid as a function of the assessed temperature. 6184.The method of claim 6155, further comprising assessing a temperature inor proximate the opening, and increasing the flow of oxidizing fluid asthe assessed temperature decreases.
 6185. The method of claim 6155,further comprising controlling the flow of oxidizing fluid to maintain atemperature in or proximate the opening at a temperature less than apre-selected temperature.
 6186. A system configurable to heat an oilshale formation, comprising: a heater configurable to be placed in anopening in the formation, wherein the heater is configurable to provideheat to at least a portion of the formation during use; an oxidizingfluid source, wherein an oxidizing fluid is selected to oxidize at leastsome hydrocarbons at a reaction zone during use such that heat isgenerated in the reaction zone; a first conduit configurable to beplaced in the opening, wherein the first conduit is configurable toprovide the oxidizing fluid from the oxidizing fluid source to thereaction zone in the formation during use; and; a second conduitconfigurable to be placed in the opening, wherein the second conduit isconfigurable to remove a product of oxidation from the opening duringuse; and wherein the system is configurable to allow the generated heatto transfer from the reaction zone to the formation during use. 6187.The system of claim 6186, wherein the second conduit is configurable tocontrol the concentration of oxygen in the opening during use such thatthe concentration of oxygen in the opening is substantially constant inthe opening.
 6188. The system of claim 6186, wherein the second conduitcomprises orifices, and wherein the second conduit comprises a greaterconcentration of orifices towards an upper end of the second conduit.6189. The system of claim 6186, wherein the first conduit comprisesorifices that direct oxidizing fluid in a direction substantiallyopposite the second conduit.
 6190. The system of claim 6186, wherein thesecond conduit comprises orifices that remove the oxidation product froma direction substantially opposite the first conduit.
 6191. The systemof claim 6186, wherein the second conduit is configurable to remove aproduct of oxidation from the opening during use such that the reactionzone comprises a substantially uniform temperature profile.
 6192. Thesystem of claim 6186, wherein a flow of the oxidizing fluid can bevaried along a portion of a length of the first conduit,
 6193. Thesystem of claim 6186, wherein the oxidizing fluid is configurable togenerate heat in the reaction zone such that the oxidizing fluid istransported through the reaction zone substantially by diffusion. 6194.The system of claim 6186, wherein the system is configurable to allowheat to transfer from the reaction zone to a pyrolysis zone in theformation during use.
 6195. The system of claim 6186, wherein the systemis configurable to allow heat to transfer substantially by conductionfrom the reaction zone to the formation during use.
 6196. The system ofclaim 6186, wherein a flow of oxidizing fluid can be controlled along atleast a portion of a length of the first conduit such that a temperaturecan be controlled along at least a portion of the length of the firstconduit during use.
 6197. The system of claim 6186, wherein a flow ofoxidizing fluid can be controlled along at least a portion of the lengthof the first conduit such that a heating rate in at least a portion ofthe formation can be controlled.
 6198. The system of claim 6186, whereinthe oxidizing fluid is configurable to generate heat in the reactionzone during use such that the oxidizing fluid is transported through thereaction zone during use substantially by diffusion, wherein a rate ofdiffusion can controlled by a temperature of the reaction zone. 6199.The system of claim 6186, wherein the first conduit comprises orifices,and wherein the orifices are configurable to provide the oxidizing fluidinto the opening during use.
 6200. The system of claim 6186, wherein thefirst conduit comprises critical flow orifices, and wherein the criticalflow orifices are configurable to control a flow of the oxidizing fluidsuch that a rate of oxidation in the formation is controlled during use.6201. The system of claim 6186, wherein the second conduit is furtherconfigurable to remove an oxidation product such that the oxidationproduct transfers heat to the oxidizing fluid in the first conduitduring use.
 6202. The system of claim 6186, wherein a pressure of theoxidizing fluid in the first conduit and a pressure of the oxidationproduct in the second conduit are controlled during use such that aconcentration of the oxidizing fluid in along the length of the conduitis substantially uniform.
 6203. The system of claim 6186, wherein theoxidation product is substantially inhibited from flowing into portionsof the formation beyond the reaction zone during use.
 6204. The systemof claim 6186, wherein the oxidizing fluid is substantially inhibitedfrom flowing into portions of the formation beyond the reaction zoneduring use.
 6205. The system of claim 6186, wherein the portion of theformation extends radially from the opening a distance of less thanapproximately 3 m.
 6206. The system of claim 6186, wherein the reactionzone extends radially from the opening a distance of less thanapproximately 3 m.
 6207. The system of claim 6186, wherein the system isfurther configurable such that transferred heat can pyrolyze at leastsome hydrocarbons in the pyrolysis zone.
 6208. The system of claim 6186,wherein the heater is configured to be placed in an opening in theformation and wherein the heater is configured to provide heat to atleast a portion of the formation during use.
 6209. The system of claim6186, wherein the first conduit is configured to be placed in theopening, and wherein the first conduit is configured to provide theoxidizing fluid from the oxidizing fluid source to the reaction zone inthe formation during use.
 6210. The system of claim 6186, wherein theflow of oxidizing fluid can be controlled along at least a segment ofthe first conduit.
 6211. The system of claim 6186, wherein the secondconduit is configured to be placed in the opening, and wherein thesecond conduit is configured to remove a product of oxidation from theopening during use.
 6212. The system of claim 6186, wherein the systemis configured to allow heat to transfer from the reaction zone to theformation during use.
 6213. An in situ method for heating an oil shaleformation, comprising: heating a portion of the formation to atemperature sufficient to support reaction of hydrocarbons within theportion of the formation with an oxidizing fluid; providing theoxidizing fluid to a reaction zone in the formation; allowing theoxidizing fluid to react with at least a portion of the hydrocarbons inthe reaction zone to generate heat in the reaction zone; removing anoxidation product from the opening; and transferring the generated heatfrom the reaction zone to the formation.
 6214. The method of claim 6213,further comprising removing the oxidation product such that aconcentration of oxygen in the opening is substantially constant in theopening.
 6215. The method of claim 6213, further comprising removing theoxidation product from the opening and maintaining a substantiallyuniform temperature profile within the reaction zone.
 6216. The methodof claim 6213, further comprising transporting the oxidizing fluidthrough the reaction zone substantially by diffusion.
 6217. The methodof claim 6213, further comprising transporting the oxidizing fluidthrough the reaction zone by diffusion, wherein a rate of diffusion iscontrolled by a temperature of the reaction zone.
 6218. The method ofclaim 6213, further comprising allowing heat to transfer from thereaction zone to a pyrolysis zone in the formation.
 6219. The method ofclaim 6213, further comprising allowing heat to transfer from thereaction zone to the formation substantially by conduction.
 6220. Themethod of claim 6213, further comprising controlling a flow of theoxidizing fluid along at least a portion of the length of the reactionzone such that a temperature is controlled along at least a portion ofthe length of the reaction zone.
 6221. The method of claim 6213, furthercomprising controlling a flow of the oxidizing fluid along at least aportion of the length of the reaction zone such that a heating rate iscontrolled along at least a portion of the length of the reaction zone.6222. The method of claim 6213, further comprising allowing at least aportion of the oxidizing fluid into the opening through orifices of aconduit placed in the opening.
 6223. The method of claim 6213, furthercomprising controlling a flow of the oxidizing fluid with critical floworifices in a conduit placed in the opening such that a rate ofoxidation is controlled.
 6224. The method of claim 6213, furthercomprising controlling a flow of the oxidizing fluid with a spacing ofcritical flow orifices in a conduit placed in the opening.
 6225. Themethod of claim 6213, further comprising controlling a flow of theoxidizing fluid with a diameter of critical flow orifices in a conduitplaced in the opening.
 6226. The method of claim 6213, furthercomprising increasing a flow of the oxidizing fluid in the opening toaccommodate an increase in a volume of the reaction zone such that arate of oxidation is substantially constant over time within thereaction zone.
 6227. The method of claim 6213, wherein a conduit isplaced in the opening, and further comprising cooling the conduit withthe oxidizing fluid to reduce heating of the conduit by oxidation. 6228.The method of claim 6213, further comprising removing an oxidationproduct from the formation through a conduit placed in the opening.6229. The method of claim 6213, further comprising removing an oxidationproduct from the formation through a conduit placed in the opening andsubstantially inhibiting the oxidation product from flowing intoportions of the formation beyond the reaction zone.
 6230. The method ofclaim 6213, further comprising substantially inhibiting the oxidizingfluid from flowing into portions of the formation beyond the reactionzone.
 6231. The method of claim 6213, further comprising removing waterfrom the formation prior to heating the portion.
 6232. The method ofclaim 6213, further comprising providing additional heat to theformation from an electric heater placed in the opening.
 6233. Themethod of claim 6213, further comprising providing additional heat tothe formation from an electric heater placed in the opening such thatthe oxidizing fluid continuously oxidizes at least a portion of thehydrocarbons in the reaction zone.
 6234. The method of claim 6213,further comprising providing additional heat to the formation from anelectric heater placed in the opening such that a constant heat rate inthe formation is maintained.
 6235. The method of claim 6213, furthercomprising providing additional heat to the formation from an electricheater placed in the opening such that the oxidation of at least aportion of the hydrocarbons does not burn out.
 6236. The method of claim6213, further comprising generating electricity using oxidation productsremoved from the formation.
 6237. The method of claim 6213, furthercomprising using oxidation products removed from the formation in an aircompressor.
 6238. The method of claim 6213, further comprisingincreasing a flow of the oxidizing fluid in the opening to accommodatean increase in a volume of the reaction zone over time.
 6239. The methodof claim 6213, further comprising increasing the amount of heat providedto the formation by increasing the reaction zone.
 6240. The method ofclaim 6213, further comprising assessing a temperature in or proximatethe opening, and controlling the flow of oxidizing fluid as a functionof the assessed temperature.
 6241. The method of claim 6213, furthercomprising assessing a temperature in or proximate the opening, andincreasing the flow of oxidizing fluid as the assessed temperaturedecreases.
 6242. The method of claim 6213, further comprisingcontrolling the flow of oxidizing fluid to maintain a temperature in orproximate the opening at a temperature less than a pre-selectedtemperature.
 6243. A method of treating an oil shale formation in situ,comprising: providing heat from one or more heat sources to at least oneportion of the formation; allowing the heat to transfer from the one ormore heat sources to a selected section of the formation; controllingthe heat from the one or more heat sources such that an averagetemperature within at least a selected section of the formation is lessthan about 375° C.; producing a mixture from the formation from aproduction well; and controlling heating in or proximate the productionwell to produce a selected yield of non-condensable hydrocarbons in theproduced mixture.
 6244. The method of claim 6243, further comprisingcontrolling heating in or proximate the production well to produce aselected yield of condensable hydrocarbons in the produced mixture.6245. The method of claim 6243, wherein the mixture comprises more thanabout 50 weight percent non-condensable hydrocarbons.
 6246. The methodof claim 6243, wherein the mixture comprises more than about 50 weightpercent condensable hydrocarbons.
 6247. The method of claim 6243,wherein the average temperature and a pressure within the formation arecontrolled such that production of carbon dioxide is substantiallyinhibited.
 6248. The method of claim 6243, heating in or proximate theproduction well is controlled such that production of carbon dioxide issubstantially inhibited.
 6249. The method of claim 6243, wherein atleast a portion of the mixture produced from a first portion of theformation at a lower temperature is recycled into a second portion ofthe formation at a higher temperature such that production of carbondioxide is substantially inhibited.
 6250. The method of claim 6243,wherein the mixture comprises a volume ratio of molecular hydrogen tocarbon monoxide of about 2 to 1, and wherein producing the mixture iscontrolled such that the volume ratio is maintained between about 1.8 to1 and about 2.2 to
 1. 6251. The method of claim 6243, wherein the heatprovided from at least one heat source is transferred to the formationsubstantially by conduction.
 6252. The method of claim 6243, wherein themixture is produced from the formation when a partial pressure ofhydrogen in at least a portion the formation is at least about 0.5 barsabsolute.
 6253. The method of claim 6243, wherein at least one heatsource comprises a heater.
 6254. A method of treating an oil shaleformation in situ, comprising: providing heat from one or more heatsources to at least one portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; controlling the heat from the one or more heat sources suchthat an average temperature within at least a selected section of theformation is less than about 375 °C.; and producing a mixture from theformation.
 6255. The method of claim 6254, removing a fluid from theformation through a production well.
 6256. The method of claim 6254,further comprising removing a liquid through a production well. 6257.The method of claim 6254, further comprising removing water through aproduction well.
 6258. The method of claim 6254, further comprisingremoving a fluid through a production well prior to providing heat tothe formation.
 6259. The method of claim 6254, further comprisingremoving water from the formation through a production well prior toproviding heat to the formation.
 6260. The method of claim 6254, furthercomprising removing the fluid through a production well using a pump.6261. The method of claim 6254, further comprising removing a fluidthrough a conduit.
 6262. The method of claim 6254, wherein the heatprovided from at least one heat source is transferred to the formationsubstantially by conduction.
 6263. The method of claim 6254, wherein themixture is produced from the formation when a partial pressure ofhydrogen in at least a portion the formation is at least about 0.5 barsabsolute.
 6264. The method of claim 6254, wherein at least one heatsource comprises a heater.
 6265. A method of treating an oil shaleformation in situ, comprising: providing heat from one or more heatsources to at least one portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; controlling the heat from the one or more heat sources suchthat an average temperature within at least a selected section of theformation is less than about 375° C.; measuring a temperature within awellbore placed in the formation; and producing a mixture from theformation.
 6266. The method of claim 6265, further comprising measuringthe temperature using a moveable thermocouple.
 6267. The method of claim6265, further comprising measuring the temperature using an opticalfiber assembly.
 6268. The method of claim 6265, further comprisingmeasuring the temperature within a production well.
 6269. The method ofclaim 6265, further comprising measuring the temperature within a heaterwell.
 6270. The method of claim 6265, further comprising measuring thetemperature within a monitoring well.
 6271. The method of claim 6265,further comprising providing a pressure wave from a pressure wave sourceinto the wellbore, wherein the wellbore comprises a plurality ofdiscontinuities along a length of the wellbore, measuring a reflectionsignal of the pressure wave, and using the reflection signal to assessat least one temperature between at least two discontinuities.
 6272. Themethod of claim 6265, further comprising assessing an averagetemperature in the formation using one or more temperatures measuredwithin at least one wellbore.
 6273. The method of claim 6265, whereinthe heat provided from at least one heat source is transferred to theformation substantially by conduction.
 6274. The method of claim 6265,wherein the mixture is produced from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 6275. The method of claim 6265, wherein atleast one heat source comprises a heater.
 6276. An in situ method ofmeasuring assessing a temperature within a wellbore in an oil shaleformation, comprising: providing a pressure wave from a pressure wavesource into the wellbore, wherein the wellbore comprises a plurality ofdiscontinuities along a length of the wellbore; measuring a reflectionsignal of the pressure wave; and using the reflection signal to assessat least one temperature between at least two discontinuities.
 6277. Themethod of claim 6276, wherein the plurality of discontinuities areplaced along a length of a conduit placed in the wellbore.
 6278. Themethod of claim 6277, wherein the pressure wave is propagated through awall of the conduit.
 6279. The method of claim 6277, wherein theplurality of discontinuities comprises collars placed within theconduit.
 6280. The method of claim 6277, wherein the plurality ofdiscontinuities comprises welds placed within the conduit.
 6281. Themethod of claim 6276, wherein determining the at least one temperaturebetween at least the two discontinuities comprises relating a velocityof the pressure wave between discontinuities to the at least onetemperature.
 6282. The method of claim 6276, further comprisingmeasuring a reference signal of the pressure wave within the wellbore atan ambient temperature.
 6283. The method of claim 6276, furthercomprising measuring a reference signal of the pressure wave within thewellbore at an ambient temperature, and then determining the at leastone temperature between at least the two discontinuities by comparingthe measured signal to the reference signal.
 6284. The method of claim6276, wherein the at least one temperature is a temperature of a gasbetween at least the two discontinuities.
 6285. The method of claim6276, wherein the wellbore comprises a production well.
 6286. The methodof claim 6276, wherein the wellbore comprises a heater well.
 6287. Themethod of claim 6276, wherein the wellbore comprises a monitoring well.6288. The method of claim 6276, wherein the pressure wave sourcecomprises a solenoid valve.
 6289. The method of claim 6276, wherein thepressure wave source comprises an explosive device.
 6290. The method ofclaim 6276, wherein the pressure wave source comprises a sound device.6291. The method of claim 6276, wherein the pressure wave is propagatedthrough the wellbore.
 6292. The method of claim 6276, wherein theplurality of discontinuities have a spacing between each discontinuityof about 5 m.
 6293. The method of claim 6276, further comprisingrepeatedly providing the pressure wave into the wellbore at a selectedfrequency and continuously measuring the reflected signal to increase asignal-to-noise ratio of the reflected signal.
 6294. The method of claim6276, further comprising providing heat from one or more heat sources toa portion of the formation.
 6295. The method of claim 6276, furthercomprising pyrolyzing at least some hydrocarbons within a portion of theformation.
 6296. The method of claim 6276, further comprising generatingsynthesis gas in at least a portion of the formation.
 6297. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least one portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; controlling the heat from the one ormore heat sources such that an average temperature within at least amajority of the selected section of the formation is less than about375° C.; and producing a mixture from the formation through a heaterwell.
 6298. The method of claim 6297, wherein producing the mixturethrough the heater well increases a production rate of the mixture fromthe formation.
 6299. The method of claim 6297, further comprisingproviding heat using at least 2 heat sources.
 6300. The method of claim6297, wherein the one or more heat sources comprise at least two heatsources, and wherein superposition of heat from at least the two heatsources pyrolyzes at least some hydrocarbons with the selected sectionof the formation.
 6301. The method of claim 6297, wherein the one ormore heat sources comprise a pattern of heat sources in a formation, andwherein superposition of heat from the pattern of heat sources pyrolyzesat least some hydrocarbons with the selected section of the formation.6302. The method of claim 6297, wherein heating of a majority ofselected section is controlled such that a temperature of the majorityof the selected section is less than about 375° C.
 6303. The method ofclaim 6297, wherein the heat provided from at least one heat source istransferred to the formation substantially by conduction.
 6304. Themethod of claim 6297, wherein the mixture is produced from the formationwhen a partial pressure of hydrogen in at least a portion the formationis at least about 0.5 bars absolute.
 6305. The method of claim 6297,wherein at least one heat source comprises a heater.
 6306. A method oftreating an oil shale formation in situ, comprising: providing heat fromone or more heat sources to at least one portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; wherein heating is provided from atleast a first heat source and at least a second heat source, wherein thefirst heat source has a first heating cost and the second heat sourcehas a second heating cost; controlling a heating rate of at least aportion of the selected section to preferentially use the first heatsource when the first heating cost is less than the second heating cost;and controlling the heat from the one or more heat sources to pyrolyzeat least some hydrocarbon in the selected section of the formation.6307. The method of claim 6306, further comprising controlling theheating rate such that a temperature within at least a majority of theselected section of the formation is less than about 375° C.
 6308. Themethod of claim 6306, further comprising providing heat using at least 2heat sources.
 6309. The method of claim 6306, wherein the one or moreheat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons with the selected section of the formation.6310. The method of claim 6306, wherein the one or more heat sourcescomprise a pattern of heat sources in a formation, and whereinsuperposition of heat from the pattern of heat sources pyrolyzes atleast some hydrocarbons with the selected section of the formation.6311. The method of claim 6306, further comprising controlling theheating to preferentially use the second heat source when the secondheating cost is less than the first heating cost.
 6312. The method ofclaim 6306, further comprising producing a mixture from the formation.6313. The method of claim 6306, wherein heating of a majority ofselected section is controlled such that a temperature of the majorityof the selected section is less than about 375° C.
 6314. The method ofclaim 6306, wherein the heat provided from at least one heat source istransferred to the formation substantially by conduction.
 6315. Themethod of claim 6306, wherein at least one heat source comprises aheater.
 6316. The method of claim 6306, further comprising producing amixture from the formation when a partial pressure of hydrogen in atleast a portion the formation is at least about 0.5 bars absolute. 6317.A method of treating an oil shale formation in situ, comprising:providing heat from one or more heat sources to at least one portion ofthe formation; allowing the heat to transfer from the one or more heatsources to a selected section of the formation; wherein heating isprovided from at least a first heat source and at least a second heatsource, wherein the first heat source has a first heating cost and thesecond heat source has a second heating cost; controlling a heating rateof at least a portion of the selected section such that a costassociated with heating the selected section is minimized; andcontrolling the heat from the one or more heat sources to pyrolyze atleast some hydrocarbon in at least a portion of the selected section ofthe formation.
 6318. The method of claim 6317, wherein the heating rateis varied within a day depending on a cost associated with heating atvarious times in the day.
 6319. The method of claim 6317, furthercomprising controlling the heating rate such that a temperature withinat least a majority of the selected section of the formation is lessthan about 375° C.
 6320. The method of claim 6317, further comprisingproviding heat using at least 2 heat sources.
 6321. The method of claim6317, wherein the one or more heat sources comprise at least two heatsources, and wherein superposition of heat from at least the two heatsources pyrolyzes at least some hydrocarbons with the selected sectionof the formation.
 6322. The method of claim 6317, wherein the one ormore heat sources comprise a pattern of heat sources in a formation, andwherein superposition of heat from the pattern of heat sources pyrolyzesat least some hydrocarbons with the selected section of the formation.6323. The method of claim 6317, further comprising producing a mixturefrom the formation.
 6324. The method of claim 6317, wherein heating of amajority of selected section is controlled such that a temperature ofthe majority of the selected section is less than about 375° C. 6325.The method of claim 6317, wherein the heat provided from at least oneheat source is transferred to the formation substantially by conduction.6326. The method of claim 6317, wherein at least one heat sourcecomprises a heater.
 6327. The method of claim 6317, further comprisingproducing a mixture from the formation when a partial pressure ofhydrogen in at least a portion the formation is at least about 0.5 barsabsolute.
 6328. A method for controlling an in situ system of treatingan oil shale formation, comprising: monitoring at least one acousticevent within the formation using at least one acoustic detector placedwithin a wellbore in the formation; recording at least one acousticevent with an acoustic monitoring system; analyzing at least oneacoustic event to determine at least one property of the formation; andcontrolling the in situ system based on the analysis of the at least oneacoustic event.
 6329. The method of claim 6328, wherein the at least oneacoustic event comprises a seismic event.
 6330. The method of claim6328, wherein the method is continuously operated.
 6331. The method ofclaim 6328, wherein the acoustic monitoring system comprises a seismicmonitoring system.
 6332. The method of claim 6328, further comprisingrecording the at least one acoustic event with the acoustic monitoringsystem.
 6333. The method of claim 6328, further comprising monitoringmore than one acoustic event simultaneously with the acoustic monitoringsystem.
 6334. The method of claim 6328, further comprising monitoringthe at least one acoustic event at a sampling rate of about at leastonce every 0.25 milliseconds.
 6335. The method of claim 6328, whereinanalyzing the at least one acoustic event comprises interpreting the atleast one acoustic event.
 6336. The method of claim 6328, wherein the atleast one property of the formation comprises a location of at least onefracture in the formation.
 6337. The method of claim 6328, wherein theat least one property of the formation comprises an extent of at leastone fracture in the formation.
 6338. The method of claim 6328, whereinthe at least one property of the formation comprises an orientation ofat least one fracture in the formation.
 6339. The method of claim 6328,wherein the at least one property of the formation comprises a locationand an extent of at least one fracture in the formation.
 6340. Themethod of claim 6328, wherein controlling the in situ system comprisesmodifying a temperature of the in situ system.
 6341. The method of claim6328, wherein controlling the in situ system comprises modifying apressure of the in situ system.
 6342. The method of claim 6328, whereinthe at least one acoustic detector comprises a geophone.
 6343. Themethod of claim 6328, wherein the at least one acoustic detectorcomprises a hydrophone.
 6344. The method of claim 6328, furthercomprising providing heat to at least a portion of the formation. 6345.The method of claim 6328, further comprising pyrolyzing hydrocarbonswithin at least a portion of the formation.
 6346. The method of claim6328, further comprising providing heat from one or more heat sources toa portion of the formation.
 6347. The method of claim 6328, furthercomprising pyrolyzing at least some hydrocarbons within a portion of theformation.
 6348. The method of claim 6328, further comprising generatingsynthesis gas in at least a portion of the formation.
 6349. A method ofpredicting characteristics of a formation fluid produced from an in situprocess, wherein the in situ process is used for treating an oil shaleformation, comprising: determining an isothermal experimentaltemperature that can be used when treating a sample of the formation,wherein the isothermal experimental temperature is correlated to aselected in situ heating rate for the formation; and treating a sampleof the formation at the determined isothermal experimental temperature,wherein the experiment is used to assess at least one productcharacteristic of the formation fluid produced from the formation forthe selected heating rate.
 6350. The method of claim 6349, furthercomprising determining the at least one product characteristic at aselected pressure.
 6351. The method of claim 6349, further comprisingmodifying the selected heating rate so that at least one desired productcharacteristic of the formation fluid is obtained.
 6352. The method ofclaim 6349, further comprising using a selected well spacing in theformation to determine the selected heating rate.
 6353. The method ofclaim 6349, further comprising using a selected heat input into theformation to determine the selected heating rate.
 6354. The method ofclaim 6349, further comprising using at least one property of theformation to determine the selected heating rate.
 6355. The method ofclaim 6349, further comprising selecting a desired heating rate suchthat at least one desired product characteristic of the formation fluidis obtained.
 6356. The method of claim 6349, further comprisingdetermining the isothermal temperature using an equation that estimatesa temperature in which a selected amount of hydrocarbons in theformation are converted.
 6357. The method of claim 6349, wherein theselected heating rate is less than about 1° C. per day.
 6358. The methodof claim 6349, wherein the sample is treated in an insulated vessel.6359. The method of claim 6349, wherein at least one assessed producedcharacteristic is used to design at least one surface processing system,wherein the surface processing system is used to treat produced fluidson the surface.
 6360. The method of claim 6349, wherein the formation istreated using a heating rate of about the selected heating rate. 6361.The method of claim 6349, further comprising using at least one productcharacteristic to assess a pressure to be maintained in the formationduring treatment.
 6362. A method of treating an oil shale formation insitu, comprising: providing heat from one or more heat sources to atleast one portion of the formation; allowing the heat to transfer fromthe one or more heat sources to a selected section of the formation;adding hydrogen to the selected section after a temperature of theselected section is at least about 270° C.; and producing a mixture fromthe formation.
 6363. The method of claim 6362, wherein the temperatureof the selected section is at least about 290° C.
 6364. The method ofclaim 6362, wherein the temperature of the selected section is at leastabout 320° C.
 6365. The method of claim 6362, wherein the temperature ofthe selected section is less than about 375° C.
 6366. The method ofclaim 6362, wherein the temperature of the selected section is less thanabout 400° C.
 6367. The method of claim 6362, wherein the heat providedfrom at least one heat source is transferred to the formationsubstantially by conduction.
 6368. The method of claim 6362, wherein themixture is produced from the formation when a partial pressure ofhydrogen in at least a portion the formation is at least about 0.5 barsabsolute.
 6369. The method of claim 6362, wherein at least one heatsource comprises a heater.
 6370. A method of treating an oil shaleformation in situ, comprising: providing heat from one or more heatsources to at least one portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; and controlling a temperature of a majority of the selectedsection by selectively adding hydrogen to the formation.
 6371. Themethod of claim 6370, further comprising controlling the temperaturesuch that the temperature is less than about 375° C.
 6372. The method ofclaim 6370, further comprising controlling the temperature such that thetemperature is less than about 400° C.
 6373. The method of claim 6370,further comprising controlling a heating rate such that the temperatureis less than about 375° C.
 6374. The method of claim 6370, wherein theone or more heat sources comprise a pattern of heat sources in aformation, and wherein superposition of heat from the pattern of heatsources pyrolyzes at least some hydrocarbons with the selected sectionof the formation.
 6375. The method of claim 6370, further comprisingproducing a mixture from the formation.
 6376. The method of claim 6370,wherein the heat provided from at least one heat source is transferredto the formation substantially by conduction.
 6377. The method of claim6370, further comprising producing a mixture from the formation when apartial pressure of hydrogen in at least a portion the formation is atleast about 0.5 bars absolute.
 6378. The method of claim 6370, whereinat least one heat source comprises a heater.
 6379. A method of treatingan oil shale formation in situ, comprising: providing heat from one ormore heat sources to at least a portion of the formation; allowing theheat to transfer from at least the portion to a selected section of theformation; and producing fluids from the formation wherein at least aportion of the produced fluids have been heated by the heat provided byone or more of the heat sources, and wherein at least a portion of theproduced fluids are produced at a temperature greater than about 200° C.6380. The method of claim 6379 wherein at least a portion of theproduced fluids are produced at a temperature greater than about 250° C.6381. The method of claim 6379 wherein at least a portion of theproduced fluids are produced at a temperature greater than about 300° C.6382. The method of claim 6379, further comprising varying the heatprovided to the one or more heat sources to vary heat in at least aportion of the produced fluids.
 6383. The method of claim 6379 whereinthe produced fluids are produced from a well comprising at least one ofthe heat sources, and further comprising varying the heat provided tothe one or more heat sources to vary heat in at least a portion of theproduced fluids.
 6384. The method of claim 6379, further comprisingproviding at least a portion of the produced fluids to a hydrotreatingunit.
 6385. The method of claim 6379, further comprising providing atleast a portion of the produced fluids to a hydrotreating unit, andfurther comprising varying the heat provided to the one or more heatsources to vary heat in at least a portion of the produced fluidsprovided to the hydrotreating unit.
 6386. The method of claim 6379,further comprising providing at least a portion of the produced fluidsto a hydrotreating unit, and using heat in the produced fluids whenhydrotreating at least a portion of the produced fluids.
 6387. Themethod of claim 6379, further comprising providing at least a portion ofthe produced fluids to a hydrotreating unit, and hydrotreating at leasta portion of the produced fluids without using a surface heater to heatproduced fluids.
 6388. The method of claim 6379, further comprising:providing at least a portion of the produced fluids to a hydrotreatingunit; and hydrotreating at least a portion of the produced fluids;wherein at least 50% of heat used for hydrotreating is provided by heatin the produced fluids.
 6389. The method of claim 6379, furthercomprising providing at least a portion of the produced fluids to ahydrotreating unit, wherein at least a portion of the produced fluidsare provided to the hydrotreating unit via an insulated conduit, andwherein the insulated conduit is insulated to inhibit heat loss from theproduced fluids.
 6390. The method of claim 6379, further comprisingproviding at least a portion of the produced fluids to a hydrotreatingunit, wherein at least a portion of the produced fluids are provided tothe hydrotreating unit via a heated conduit.
 6391. The method of claim6379, further comprising providing at least a portion of the producedfluids to a hydrotreating unit wherein the produced fluids are producedat a wellhead, and wherein at least a portion of the produced fluids areprovided to the hydrotreating unit at a temperature that is within about50° C. of the temperature of the produced fluids at the wellhead. 6392.The method of claim 6379, further comprising hydrotreating at least aportion of the produced fluids such that the volume of hydrotreatedproduced fluids is about 4% greater than a volume of the producedfluids.
 6393. The method of claim 6379, further comprising providing atleast a portion of the produced fluids to a hydrotreating unit whereinthe produced fluids comprise molecular hydrogen, and using the molecularhydrogen in the produced fluids to hydrotreat at least a portion of theproduced fluids.
 6394. The method of claim 6379, further comprisingproviding at least a portion of the produced fluids to a hydrotreatingunit wherein the produced fluids comprise molecular hydrogen,hydrotreating at least a portion of the produced fluids, and wherein atleast 50% of molecular hydrogen used for hydrotreating is provided bythe molecular hydrogen in the produced fluids.
 6395. The method of claim6379 wherein the produced fluids comprise molecular hydrogen, separatingat least a portion of the molecular hydrogen from the produced fluids,and providing at least a portion of the separated molecular hydrogen toa surface treatment unit.
 6396. The method of claim 6379 wherein theproduced fluids comprise molecular hydrogen, separating at least aportion of the molecular hydrogen from the produced fluids, andproviding at least a portion of the separated molecular hydrogen to anin situ treatment area.
 6397. The method of claim 6379 furthercomprising providing a portion of the produced fluids to an olefingenerating unit.
 6398. The method of claim 6379 further comprisingproviding a portion of the produced fluids to a steam cracking unit.6399. The method of claim 6379, further comprising providing at least aportion of the produced fluids to an olefin generating unit, and furthercomprising varying heat provided to the one or more heat sources to varythe heat in at least a portion of the produced fluids provided to theolefin generating unit.
 6400. The method of claim 6379, furthercomprising providing at least a portion of the produced fluids to anolefin generating unit, and using heat in the produced fluids whengenerating olefins from at least a portion of the produced fluids. 6401.The method of claim 6379, further comprising providing at least aportion of the produced fluids to an olefin generating unit, andgenerating olefins from at least a portion of the produced fluidswithout using a surface heater to heat produced fluids.
 6402. The methodof claim 6379, further comprising providing at least a portion of theproduced fluids to an olefin generating unit, and generating olefinsfrom at least a portion of the produced fluids, and wherein at least 50%of the heat used for generating olefins is provided by heat in theproduced fluids.
 6403. The method of claim 6379, further comprisingproviding at least a portion of the produced fluids to an olefingenerating unit wherein at least a portion of the produced fluids areprovided to the olefin generating unit via an insulated conduit, andwherein the insulated conduit is insulated to inhibit heat loss from theproduced fluids.
 6404. The method of claim 6379, further comprisingproviding at least a portion of the produced fluids to an olefingenerating unit wherein at least a portion of the produced fluids areprovided to the olefin generating unit via a heated conduit.
 6405. Themethod of claim 6379, further comprising providing at least a portion ofthe produced fluids to an olefin generating unit wherein the producedfluids are produced at a wellhead, and wherein at least a portion of theproduced fluids are provided to the olefin generating unit at atemperature that is within about 50° C. of the temperature of theproduced fluids at the wellhead.
 6406. The method of claim 6379 furthercomprising removing heat from the produced fluids in a heat exchanger.6407. The method of claim 6379 further comprising separating theproduced fluids into two or more streams comprising at least a syntheticcondensate stream, and a non-condensable fluid stream.
 6408. The methodof claim 6379 further comprising providing at least a portion of theproduced fluids to a separating unit, and separating at least a portionof the produced fluids into two or more streams.
 6409. The method ofclaim 6379 further comprising providing at least a portion of theproduced fluids to a separating unit, and separating at least a portionof the produced fluids into two or more streams, and further comprisingseparating at least one of such streams into two or more substreams.6410. The method of claim 6379 further comprising providing at least aportion of the produced fluids to a separating unit, and separating atleast a portion of the produced fluids into three or more streams, andwherein such streams comprise at least a top stream, a bottom stream,and a middle stream.
 6411. The method of claim 6379, further comprisingproviding at least a portion of the produced fluids to a separatingunit, and further comprising varying heat provided to the one or moreheat sources to vary the heat in at least a portion of the producedfluids provided to the separating unit.
 6412. The method of claim 6379,further comprising providing at least a portion of the produced fluidsto a separating unit, and using heat in the produced fluids whenseparating at least a portion of the produced fluids.
 6413. The methodof claim 6379, further comprising providing at least a portion of theproduced fluids to a separating unit, and separating at least a portionof the produced fluids without using a surface heater to heat producedfluids.
 6414. The method of claim 6379, further comprising providing atleast a portion of the produced fluids to a separating unit, andseparating at least a portion of the produced fluids, and wherein atleast 50% of the heat used for separating is provided by heat in theproduced fluids.
 6415. The method of claim 6379, further comprisingproviding at least a portion of the produced fluids to a separating unitwherein at least a portion of the produced fluids are provided to theseparating unit via an insulated conduit, and wherein the insulatedconduit is insulated to inhibit heat loss from the produced fluids.6416. The method of claim 6379, further comprising providing at least aportion of the produced fluids to a separating unit wherein at least aportion of the produced fluids are provided to the separating unit via aheated conduit.
 6417. The method of claim 6379, further comprisingproviding at least a portion of the produced fluids to a separating unitwherein the produced fluids are produced at a wellhead, and wherein atleast a portion of the produced fluids are provided to the separatingunit at a temperature that is within about 50° C. of the temperature ofthe produced fluids at the wellhead.
 6418. The method of claim 6379,further comprising providing at least a portion of the produced fluidsto a separating unit, and separating at least a portion of the producedfluids into four or more streams, and wherein such streams comprise atleast a top stream, a bottoms stream, and at least two middle streamswherein one of the middle streams is heavier than the other middlestream.
 6419. The method of claim 6379, further comprising providing atleast a portion of the produced fluids to a separating unit, andseparating at least a portion of the produced fluids into five or morestreams, and wherein such streams comprise at least a top stream, abottoms stream, a naphtha stream, diesel stream, and a jet fuel stream.6420. The method of claim 6379, further comprising providing at least aportion of the produced fluids to a distillation column, and using heatin the produced fluids when distilling at least a portion of theproduced fluids.
 6421. The method of claim 6379 wherein the producedfluids comprise pyrolyzation fluids.
 6422. The method of claim 6379wherein the produced fluids comprise carbon dioxide, and furthercomprising separating at least a portion of the carbon dioxide from theproduced fluids.
 6423. The method of claim 6379 wherein the producedfluids comprise carbon dioxide, and further comprising separating atleast a portion of the carbon dioxide from the produced fluids, andutilizing at least some carbon dioxide in one or more treatmentprocesses.
 6424. The method of claim 6379 wherein the produced fluidscomprise molecular hydrogen and wherein the molecular hydrogen is usedwhen treating the produced fluids.
 6425. The method of claim 6379wherein the produced fluids comprise steam and wherein the steam is usedwhen treating the produced fluids.
 6426. The method of claim 6379,wherein the heat provided from at least one heat source is transferredto the formation substantially by conduction.
 6427. The method of claim6379, wherein the fluids are produced from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 6428. The method of claim 6379, wherein atleast one heat source comprises a heater.
 6429. A method of convertingformation fluids into olefins, comprising: converting formation fluidsinto olefins, wherein the formation fluids are obtained by: providingheat from one or more heat sources to at least a portion of theformation; allowing the heat to transfer from one or more heat sourcesto a selected section of the formation such that at least somehydrocarbons in the formation are pyrolyzed; and producing formationfluids from the formation.
 6430. The method of claim 6429 wherein theproduced fluids comprise steam.
 6431. The method of claim 6429 whereinthe produced fluids comprise steam and wherein the steam in the producedfluids comprises at least a portion of steam used in the olefingenerating unit.
 6432. The method of claim 6429, further comprisingproviding at least a portion of the produced fluids to an olefingenerating unit.
 6433. The method of claim 6429, further comprisingproviding at least a portion of the produced fluids to a steam crackingunit.
 6434. The method of claim 6429 wherein olefins comprise ethylene.6435. The method of claim 6429 wherein olefins comprise propylene. 6436.The method of claim 6429, further comprising separating liquids from theproduced fluids, and then separating olefin generating compounds fromthe produced fluids, and then providing at least a portion of the olefingenerating compounds to an olefin generating unit.
 6437. The method ofclaim 6429 wherein the produced fluids comprise molecular hydrogen, andfurther comprising removing at least a portion of the molecular hydrogenfrom the produced fluids prior to using the produced fluids to produceolefins.
 6438. The method of claim 6429 wherein the produced fluidscomprise molecular hydrogen, and further comprising separating at leasta portion of the molecular hydrogen from the produced fluids, andutilizing at least a portion of the separated molecular hydrogen in oneor more treatment processes.
 6439. The method of claim 6429 wherein theproduced fluids comprise molecular hydrogen, and further comprisingremoving at least a portion of the molecular hydrogen from the producedfluids using a hydrogen removal unit prior to using the produced fluidsto produce olefins.
 6440. The method of claim 6429 wherein the producedfluids comprises molecular hydrogen, and further comprising removing atleast a portion of the molecular hydrogen from the produced fluids usinga membrane prior to using the produced fluids to produce olefins. 6441.The method of claim 6429, further comprising generating molecularhydrogen during production of olefins, and providing at least a portionof the generated molecular hydrogen to one or more hydrotreating units.6442. The method of claim 6429, further comprising generating molecularhydrogen during production of olefins, and providing at least a portionof the generated molecular hydrogen to an in situ treatment area. 6443.The method of claim 6429, further comprising generating molecularhydrogen during production of olefins, and providing at least a portionof the generated molecular hydrogen to one or more fuel cells. Themethod of claim 6429, further comprising generating molecular hydrogenduring production of olefins, and using at least a portion of thegenerated molecular hydrogen to hydrotreat pyrolysis liquids generatedin the olefin generation plant.
 6444. The method of claim 6429 whereinthe produced fluids are at least 200° C., and further comprising usingheat in the produced fluids to produce olefins.
 6445. The method ofclaim 6429, further comprising providing at least a portion of theproduced fluids to a hydrotreating unit wherein the produced fluids areproduced at a wellhead, and wherein at least a portion of the producedfluids are provided to the olefins generating unit at a temperature thatis within about 50° C. of the temperature of the produced fluids at thewellhead.
 6446. The method of claim 6429 wherein the produced fluids canbe used to make olefins without substantial hydrotreating of theproduced fluids.
 6447. The method of claim 6429, further comprisingseparating liquids from the produced fluids, and then using at least aportion of the produced fluids to produce olefins.
 6448. The method ofclaim 6429, further comprising controlling a fluid pressure within atleast a portion of the formation to enhance production of olefingenerating compounds in the produced fluids.
 6449. The method of claim6429, further comprising controlling a temperature within at least aportion of the formation to enhance production of olefin generatingcompounds in the produced fluids.
 6450. The method of claim 6429,further comprising controlling a temperature profile within at least aportion of the formation to enhance production of olefin generatingcompounds in the produced fluids.
 6451. The method of claim 6429,further comprising controlling a heating rate within at least a portionof the formation to enhance production of olefin generating compounds inthe produced fluids.
 6452. The method of claim 6429, further comprisingproviding at least a portion of the produced fluids to an olefingenerating unit, and further comprising varying heat provided to the oneor more heat sources to vary the heat in at least a portion of theproduced fluids provided to the olefin generating unit.
 6453. The methodof claim 6429, further comprising providing at least a portion of theproduced fluids to an olefin generating unit, and using heat in theproduced fluids when generating olefins from at least a portion of theproduced fluids.
 6454. The method of claim 6429 wherein the producedfluids comprise steam, and further comprising providing at least aportion of the produced fluids to an olefin generating unit, and usingsteam in the produced fluids when generating olefins from at least aportion of the produced fluids.
 6455. The method of claim 6429 whereinthe produced fluids comprise steam, and further comprising providing atleast a portion of the produced fluids to an olefin generating unit,generating olefins from at least a portion of the produced fluids, andwherein at least some steam used for generating olefins is provided bythe steam in the produced fluids.
 6456. The method of claim 6429,further comprising providing at least a portion of the produced fluidsto an olefin generating unit wherein at least a portion of the producedfluids are provided to the olefin generating unit via an insulatedconduit, and wherein the insulated conduit is insulated to inhibit heatloss from the produced fluids.
 6457. The method of claim 6429, furthercomprising providing at least a portion of the produced fluids to anolefin generating unit wherein at least a portion of the produced fluidsare provided to the olefin generating unit via a heated conduit. 6458.The method of claim 6429, further comprising separating at least aportion of the produced fluids into one or more fractions wherein theone or more fractions comprise a naphtha fraction, and furthercomprising providing the naphtha fraction to an olefin generating unit.6459. The method of claim 6429, further comprising separating at least aportion of the produced fluids into one or more fractions wherein theone or more fractions comprise a olefin generating fraction wherein theolefin generating fraction comprises hydrocarbons having a carbon numbergreater than about 1 and a carbon number less than about 8, and furthercomprising providing the olefin generating fraction to a olefingenerating unit.
 6460. The method of claim 6429, further comprisingseparating at least a portion of the produced fluids into one or morefractions wherein the one or more fractions comprise an olefingenerating fraction wherein the olefin generating fraction compriseshydrocarbons having a carbon number greater than about 1 and a carbonnumber less than about 6, and further comprising providing the olefingenerating fraction to a olefin generating unit.
 6461. The method ofclaim 6429, further comprising providing at least the portion of theproduced fluids to a component removal unit such that at least onecomponent stream and a reduced component fluid stream are formed, andthen providing the reduced component fluid stream to an olefingenerating unit.
 6462. The method of claim 6461, wherein the componentcomprises a metal.
 6463. The method of claim 6461, wherein the componentcomprises arsenic.
 6464. The method of claim 6461, wherein the componentcomprises mercury.
 6465. The method of claim 6461, wherein the componentcomprises lead.
 6466. The method of claim 6429, further comprisingproviding at least the portion of the produced fluids to a componentremoval unit such that at least one component stream and a reducedcomponent fluid stream are formed, then providing the reduced componentfluid stream to a molecular hydrogen separating unit such that amolecular hydrogen stream and a reduced hydrogen fluid stream areformed, then providing the molecular hydrogen stream to a hydrotreatingunit, and then providing the reduced hydrogen produced fluid stream toan olefin generating unit.
 6467. The method of claim 6429 wherein theproduced fluids comprise molecular hydrogen and wherein the molecularhydrogen is used when treating the produced fluids.
 6468. The method ofclaim 6429 wherein the produced fluids comprise steam and wherein thesteam is used when treating the produced fluids.
 6469. The method ofclaim 6429, further comprising providing at least a portion of theproduced fluids to an olefin generating unit, and using heat in theproduced fluids when generating olefins from at least a portion of theproduced fluids.
 6470. The method of claim 6429 wherein the producedfluids comprise steam, and further comprising providing at least aportion of the produced fluids to an olefin generating unit, and usingsteam in the produced fluids when generating olefins from at least aportion of the produced fluids.
 6471. The method of claim 6429, furthercomprising providing at least a portion of the produced fluids to anolefin generating unit wherein at least a portion of the produced fluidsare provided to the olefin generating unit via an insulated conduit, andwherein the insulated conduit is insulated to inhibit heat loss from theproduced fluids.
 6472. The method of claim 6429, further comprisingproviding at least a portion of the produced fluids to an olefingenerating unit wherein at least a portion of the produced fluids areprovided to the olefin generating unit via a heated conduit.
 6473. Themethod of claim 6429, wherein the heat provided from at least one heatsource is transferred to the formation substantially by conduction.6474. The method of claim 6429, wherein the formation fluids areproduced from the formation when a partial pressure of hydrogen in atleast a portion the formation is at least about 0.5 bars absolute. 6475.The method of claim 6429, wherein at least one heat source comprises aheater.
 6476. A method of separating olefins from fluids produced froman oil shale formation, comprising: separating olefins from the producedfluids, wherein the produced fluids are obtained by: providing heat fromone or more heat sources to at least a portion of the formation;allowing the heat to transfer from at least one or more heat sources toa selected section of the formation; and producing fluids from theformation wherein the produced fluids comprise olefins.
 6477. The methodof claim 6476 wherein olefins comprise ethylene.
 6478. The method ofclaim 6476 wherein olefins comprise propylene.
 6479. The method of claim6476, further comprising separating liquids from the produced fluids.6480. The method of claim 6476 wherein the produced fluids comprisemolecular hydrogen, and further comprising separating at least a portionof the molecular hydrogen from the produced fluids, and utilizing atleast a portion of the separated molecular hydrogen in one or moretreatment processes.
 6481. The method of claim 6476 wherein the producedfluids comprise molecular hydrogen, and further comprising removing atleast a portion of the molecular hydrogen from the produced fluids usinga hydrogen removal unit.
 6482. The method of claim 6476 wherein theproduced fluids comprises molecular hydrogen, and further comprisingremoving at least a portion of the molecular hydrogen from the producedfluids using a membrane.
 6483. The method of claim 6476, furthercomprising controlling a fluid pressure within at least a portion of theformation to enhance production of olefins in the produced fluids. 6484.The method of claim 6476, further comprising controlling a temperaturewithin at least a portion of the formation to enhance production ofolefins in the produced fluids.
 6485. The method of claim 6476, furthercomprising controlling a temperature profile within at least a portionof the formation to enhance production of olefins in the producedfluids.
 6486. The method of claim 6476, further comprising controlling aheating rate within at least a portion of the formation to enhanceproduction of olefins in the produced fluids.
 6487. The method of claim6476, further comprising providing at least a portion of the producedfluids to an olefin generating unit, and further comprising varying heatprovided to the one or more heat sources to vary the heat in at least aportion of the produced fluids provided to the olefin generating unit.6488. The method of claim 6476, further comprising providing at least aportion of the produced fluids to an olefin generating unit, and usingheat in the produced fluids when generating olefins from at least aportion of the produced fluids.
 6489. The method of claim 6476 whereinthe produced fluids comprise steam, and further comprising providing atleast a portion of the produced fluids to an olefin generating unit, andusing steam in the produced fluids when generating olefins from at leasta portion of the produced fluids.
 6490. The method of claim 6476,further comprising providing at least a portion of the produced fluidsto an olefin generating unit wherein at least a portion of the producedfluids are provided to the olefin generating unit via an insulatedconduit, and wherein the insulated conduit is insulated to inhibit heatloss from the produced fluids.
 6491. The method of claim 6476, furthercomprising providing at least a portion of the produced fluids to anolefin generating unit wherein at least a portion of the produced fluidsare provided to the olefin generating unit via a heated conduit. 6492.The method of claim 6476, further comprising separating at least aportion of the produced fluids into one or more fractions wherein theone or more fractions comprise a naphtha fraction, and furthercomprising providing the naphtha fraction to an olefin generating unit.6493. The method of claim 6476, further comprising separating at least aportion of the produced fluids into one or more fractions wherein theone or more fractions comprise a olefin generating fraction wherein theolefin generating fraction comprises hydrocarbons having a carbon numbergreater than about 1 and a carbon number less than about 8, and furthercomprising providing the olefin generating fraction to a olefingenerating unit.
 6494. The method of claim 6476, further comprisingseparating at least a portion of the produced fluids into one or morefractions wherein the one or more fractions comprise an olefingenerating fraction wherein the olefin generating fraction compriseshydrocarbons having a carbon number greater than about 1 and a carbonnumber less than about 6, and further comprising providing the olefingenerating fraction to a olefin generating unit.
 6495. The method ofclaim 6476, further comprising providing at least the portion of theproduced fluids to a component removal unit such that at least onecomponent stream and a reduced component fluid stream are formed, andthen providing the reduced component fluid stream to an olefingenerating unit.
 6496. The method of claim 6495 wherein the componentcomprises a metal.
 6497. The method of claim 6495 wherein the componentcomprises arsenic.
 6498. The method of claim 6495 wherein the componentcomprises mercury.
 6499. The method of claim 6495 wherein the componentcomprises lead.
 6500. The method of claim 6476, further comprisingproviding at least the portion of the produced fluids to a componentremoval unit such that at least one component stream and a reducedcomponent fluid stream are formed, then providing the reduced componentfluid stream to a molecular hydrogen separating unit such that amolecular hydrogen stream and a reduced hydrogen fluid stream areformed, then providing the molecular hydrogen stream to a hydrotreatingunit, and then providing the reduced hydrogen produced fluid stream toan olefin generating unit.
 6501. The method of claim 6476, furthercomprising controlling a temperature gradient within at least a portionof the formation to enhance production of olefins in the producedfluids.
 6502. The method of claim 6476, further comprising controlling afluid pressure within at least a portion of the formation to enhanceproduction of olefins in the produced fluids.
 6503. The method of claim6476, further comprising controlling a temperature within at least aportion of the formation to enhance production of olefins in theproduced fluids.
 6504. The method of claim 6476, further comprisingcontrolling a heating rate within at least a portion of the formation toenhance production of olefins in the produced fluids.
 6505. The methodof claim 6476, further comprising separating the olefins from theproduced fluids such that an amount of molecular hydrogen utilized inone or more downstream hydrotreating units decreases.
 6506. The methodof claim 6476, further comprising removing at least a portion of theolefins prior to hydrotreating produced fluids.
 6507. A method ofenhancing phenol production from an in situ oil shale formation,comprising: controlling at least one condition within at least a portionof the formation to enhance production of phenols in formation fluid,wherein the formation fluid is obtained by: providing heat from one ormore heat sources to at least the portion of the formation; allowing theheat to transfer from at least one or more heat sources to a selectedsection of the formation; and producing formation fluids from theformation.
 6508. The method of claim 6507, further comprising separatingat least a portion of the phenols from the produced fluids.
 6509. Themethod of claim 6507 wherein controlling at least one condition in theformation comprises controlling a fluid pressure within at least aportion of the formation.
 6510. The method of claim 6507 whereincontrolling at least one condition in the formation comprisescontrolling a temperature gradient within at least a portion of theformation.
 6511. The method of claim 6507 wherein controlling at leastone condition in the formation comprises controlling a temperaturewithin at least a portion of the formation.
 6512. The method of claim6507 wherein controlling at least one condition in the formationcomprises controlling a heating rate within at least a portion of theformation.
 6513. The method of claim 6507 wherein the at least onecondition in the formation is controlled such that an average carbonnumber of the produced fluids is lowered.
 6514. The method of claim6507, further comprising separating at least a portion of the producedfluids into a phenols fraction at a wellhead using condensation. 6515.The method of claim 6507, further comprising separating at least aportion of the produced fluids into a phenols fraction at a wellheadusing fractionation.
 6516. The method of claim 6507, further comprisingseparating the produced fluids into one or more fractions wherein theone or more fractions comprise a naphtha fraction, and furthercomprising providing the naphtha fraction to an extraction unit, andseparating at least some phenols from the naphtha fraction.
 6517. Themethod of claim 6507, further comprising separating the produced fluidsinto a gas stream and a liquid stream, separating the liquid stream intoa phenols fraction and a hydrocarbon containing fraction, and providingthe hydrocarbon containing fraction to a pipeline.
 6518. The method ofclaim 6507, further comprising separating the produced fluids into oneor more fractions wherein the one or more fractions comprise a phenolsfraction, and further comprising providing the phenols fraction to anextraction unit, and separating at least some phenols from the phenolsfluids.
 6519. The method of claim 6507, further comprising separatingthe phenols from the produced fluids with a water/methanol extractionprocess.
 6520. The method of claim 6507, further comprising separatingthe phenols from the produced fluids such that an amount of molecularhydrogen utilized in one or more downstream hydrotreating unitsdecreases.
 6521. The method of claim 6507 wherein controlling acondition comprises lowering the average carbon number of the producedfluids.
 6522. The method of claim 6507, further comprising removing atleast a portion of the phenols prior to hydrotreating produced fluids.6523. The method of claim 6507, further comprising removing at least aportion of the phenols prior to hydrotreating produced fluids, andwherein removing at least the portion reduces an amount of molecularhydrogen required in a hydrotreating unit.
 6524. The method of 6507,further comprising reacting at least a portion of the phenols withmolecular hydrogen to form phenol.
 6525. The method of claim 6507,wherein the selected section has been selected for heating using anoxygen content of at least some hydrocarbons in the selected section.6526. The method of claim 6476, wherein the heat provided from at leastone heat source is transferred to the formation substantially byconduction.
 6527. The method of claim 6476, wherein the fluids areproduced from the formation when a partial pressure of hydrogen in atleast a portion the formation is at least about 0.5 bars absolute. 6528.The method of claim 6476, wherein at least one heat source comprises aheater.
 6529. A method of controlling phenol production from an oilshale formation, comprising; converting at least a portion of formationfluid into phenol, wherein the formation fluids in situ are obtained by:providing heat from one or more heat sources to at least a portion ofthe formation; allowing the heat to transfer from at least one or moreheat sources to a selected section; and producing formation fluids fromthe formation.
 6530. The method of 6529, wherein the formation fluidscomprise phenols.
 6531. The method of 6529, wherein converting at leasta portion of formation fluid into phenol comprises reacting at least aportion of the phenols with molecular hydrogen to form phenol.
 6532. Themethod of claim 6529, wherein the heat provided from at least one heatsource is transferred to the formation substantially by conduction.6533. The method of claim 6529, wherein the formation fluids areproduced from the formation when a partial pressure of hydrogen in atleast a portion the formation is at least about 0.5 bars absolute. 6534.The method of claim 6529, wherein at least one heat source comprises aheater.
 6535. A method of separating phenols from fluids produced froman oil shale formation, comprising: separating phenols from the producedfluids, wherein the produced fluids are obtained by: providing heat fromone or more heat sources to at least a portion of the formation;allowing the heat to transfer from at least one or more heat sources toa selected section of the formation; and producing fluids from theformation wherein the produced fluids comprise phenols.
 6536. The methodof claim 6535, further comprising controlling a fluid pressure within atleast a portion of the formation.
 6537. The method of claim 6535,further comprising controlling a temperature gradient within at least aportion of the formation.
 6538. The method of claim 6535, furthercomprising controlling a temperature within at least a portion of theformation.
 6539. The method of claim 6535, further comprisingcontrolling a heating rate within at least a portion of the formation.6540. The method of claim 6535 wherein separating the phenols from theproduced fluids, further comprises removing a naphtha fraction from theproduced fluids, and separating phenols from the naphtha fraction. 6541.The method of claim 6535 wherein separating the phenols from theproduced fluids, further comprises removing a phenols fraction from theproduced fluids, and separating at least some phenols from the phenolsfraction.
 6542. The method of claim 6535 wherein separating the phenolsfrom the produced fluids, further comprises removing phenols with awater/methanol extraction.
 6543. The method of claim 6535 whereinseparating the phenols from the produced fluids decreases an amount ofmolecular hydrogen utilized in one or more downstream hydrotreatingunits.
 6544. The method of claim 6535, wherein controlling a conditioncomprises lowering the average carbon number of the produced fluids.6545. The method of claim 6535, further comprising removing at least aportion of the phenols prior to hydrotreating produced fluids.
 6546. Themethod of claim 6535, further comprising removing at least a portion ofthe phenols prior to hydrotreating produced fluids, and wherein removingat least the portion reduces an amount of molecular hydrogen required ina hydrotreating unit.
 6547. The method of claim 6535, further comprisingreacting at least a portion of the phenols with molecular hydrogen toform phenol.
 6548. The method of claim 6535, wherein the heat providedfrom at least one heat source is transferred to the formationsubstantially by conduction.
 6549. The method of claim 6535, wherein thefluids are produced from the formation when a partial pressure ofhydrogen in at least a portion the formation is at least about 0.5 barsabsolute.
 6550. The method of claim 6535, wherein at least one heatsource comprises a heater.
 6551. A method of enhancing phenol productionfrom an oil shale formation, comprising: controlling at least onecondition within at least a portion of the formation to enhanceproduction of phenols in formation fluid, wherein the formation fluid isobtained by: providing heat from one or more heat sources to at least aportion of the formation; allowing the heat to transfer from at leastone or more heat sources to a selected section of the formation; andproducing formation fluids from the formation.
 6552. The method of claim6551, further comprising separating at least a portion of the phenolsfrom the produced fluids.
 6553. The method of claim 6551, furthercomprising controlling at least one condition in situ such that anaverage carbon number of the produced fluids is lowered.
 6554. Themethod of claim 6551, further comprising controlling a temperaturegradient within at least a portion of the formation.
 6555. The method ofclaim 6551, further comprising controlling a fluid pressure within atleast a portion of the formation.
 6556. The method of claim 6551,further comprising controlling a temperature within at least a portionof the formation.
 6557. The method of claim 6551, further comprisingcontrolling a heating rate within at least a portion of the formation.6558. The method of claim 6551, further comprising separating at least aportion of the produced fluids into a phenols fraction at a wellheadusing condensation.
 6559. The method of claim 6551, further comprisingseparating at least a portion of the produced fluids into a phenolsfraction at a wellhead using fractionation.
 6560. The method of claim6551, further comprising separating the produced fluids into one or morefractions wherein the one or more fractions comprise a naphtha fraction,and further comprising providing the naphtha fraction to an extractionunit, and separating at least some phenols from the naphtha fraction.6561. The method of claim 6551, further comprising separating theproduced fluids into one or more fractions wherein the one or morefractions comprise a phenols fraction, and further comprising providingthe phenols fraction to an extraction unit, and separating at least somephenols from the phenols fluids.
 6562. The method of claim 6551, furthercomprising separating the phenols from the produced fluids with awater/methanol extraction process.
 6563. The method of claim 6551,further comprising separating the phenols from the produced fluids suchthat an amount of molecular hydrogen utilized in one or more downstreamhydrotreating units decreases.
 6564. The method of claim 6551, furthercomprising removing at least a portion of the phenols prior tohydrotreating produced fluids.
 6565. The method of claim 6551, furthercomprising removing at least a portion of the phenols prior tohydrotreating produced fluids, and wherein removing at least the portionreduces an amount of molecular hydrogen required in a hydrotreatingunit.
 6566. The method of claim 6551, wherein the heat provided from atleast one heat source is transferred to the formation substantially byconduction.
 6567. The method of claim 6551, wherein the formation fluidsare produced from the formation when a partial pressure of hydrogen inat least a portion the formation is at least about 0.5 bars absolute.6568. The method of claim 6551, wherein at least one heat sourcecomprises a heater.
 6569. A method of enhancing BTEX compoundsproduction from an oil shale formation, comprising: controlling at leastone condition within at least a portion of the formation to enhanceproduction of BTEX compounds in formation fluid, wherein the formationfluid is obtained by: providing heat from one or more heat sources to atleast a portion of the formation; allowing the heat to transfer from atleast one or more heat sources to a selected section of the formation;and producing formation fluids from the formation.
 6570. The method ofclaim 6569, further comprising separating at least a portion of the BTEXcompounds from the produced fluids.
 6571. The method of claim 6569,further comprising separating at least a portion of the BTEX compoundsfrom the produced fluids via solvent extraction.
 6572. The method ofclaim 6569, further comprising separating at least a portion of the BTEXcompounds from the produced fluids via distillation.
 6573. The method ofclaim 6569, further comprising separating at least a portion of the BTEXcompounds from the produced fluids via condensation.
 6574. The method ofclaim 6569, further comprising separating at least a portion of the BTEXcompounds from the produced fluids such that an amount of molecularhydrogen utilized in one or more downstream hydrotreating unitsdecreases.
 6575. The method of claim 6569, wherein controlling at leastone condition in the formation comprises controlling a fluid pressurewithin at least a portion of the formation.
 6576. The method of claim6569, wherein controlling at least one condition in the formationcomprises controlling a temperature gradient within at least a portionof the formation.
 6577. The method of claim 6569, wherein controlling atleast one condition in the formation comprises controlling a temperaturewithin at least a portion of the formation.
 6578. The method of claim6569, wherein controlling at least one condition in the formationcomprises controlling a heating rate within at least a portion of theformation.
 6579. The method of claim 6569, further comprising removingat least a portion of the BTEX compounds prior to hydrotreating producedfluids.
 6580. The method of claim 6569, further comprising removing atleast a portion of the phenols prior to hydrotreating produced fluids,and wherein removing at least the portion reduces an amount of molecularhydrogen required in a hydrotreating unit.
 6581. The method of claim6569, wherein the heat provided from at least one heat source istransferred to the formation substantially by conduction.
 6582. Themethod of claim 6569, wherein the formation fluids are produced from theformation when a partial pressure of hydrogen in at least a portion theformation is at least about 0.5 bars absolute.
 6583. The method of claim6569, wherein at least one heat source comprises a heater.
 6584. Amethod of separating BTEX compounds from formation fluid from an oilshale formation, comprising: separating at least a portion of the BTEXcompounds from the formation fluid wherein the formation fluid isobtained by: providing heat from one or more heat sources to at least aportion of the formation; allowing the heat to transfer from at leastone or more heat sources to a selected section of the formation; andproducing fluids from the formation wherein the produced fluids compriseBTEX compounds.
 6585. The method of claim 6584, further comprisinghydrotreating at least a portion of the produced fluids after the BTEXcompounds have been separated from same.
 6586. The method of claim 6584wherein separating at least a portion of the BTEX compounds from theproduced fluids comprises extracting at least the portion of the BTEXcompounds from the produced fluids via solvent extraction.
 6587. Themethod of claim 6584 wherein separating at least a portion of the BTEXcompounds from the produced fluids comprises distilling at least theportion of the BTEX compounds from the produced fluids.
 6588. The methodof claim 6584 wherein separating at least a portion of the BTEXcompounds from the produced fluids comprises condensing at least theportion of the BTEX compounds from the produced fluids
 6589. The methodof claim 6584 wherein separating at least a portion of the BTEXcompounds from the produced fluids such that an amount of molecularhydrogen utilized in one or more downstream hydrotreating unitsdecreases.
 6590. The method of claim 6584, further comprisingcontrolling a fluid pressure within at least a portion of the formation.6591. The method of claim 6584, further comprising controlling atemperature gradient within at least a portion of the formation. 6592.The method of claim 6584, further comprising controlling a temperaturewithin at least a portion of the formation.
 6593. The method of claim6584, further comprising controlling a heating rate within at least aportion of the formation.
 6594. The method of claim 6584 whereinseparating at least the portion of BTEX compounds from the producedfluids further comprises removing a naphtha fraction from the producedfluids, and separating at least the portion of BTEX compounds from thenaphtha fraction.
 6595. The method of claim 6584, wherein separating atleast the portion of BTEX compounds from the produced fluids, furthercomprises removing a BTEX fraction from the produced fluids, andseparating at some BTEX compounds from the BTEX fraction.
 6596. Themethod of claim 6584, wherein separating at least the portion of BTEXcompounds from the produced fluids decreases an amount of molecularhydrogen utilized in one or more downstream hydrotreating units.
 6597. Amethod of in situ converting at least a portion of formation fluid intoBTEX compounds, comprising: in situ converting at least the portion ofthe formation fluid into BTEX compounds, wherein the formation fluid areobtained by: providing heat from one or more heat sources to at least aportion of the formation; allowing the heat to transfer from at leastone or more heat sources to a selected section of the formation suchthat at least some hydrocarbons in the formation are pyrolyzed; andproducing formation fluid from the formation.
 6598. The method of claim6597, further comprising providing at least a portion of the formationfluid to an BTEX generating unit.
 6599. The method of claim 6597,further comprising providing at least a portion of the formation fluidto a catalytic reforming unit.
 6600. The method of claim 6597, furthercomprising hydrotreating at least some of the formation fluid, and thenseparating the hydrotreated mixture into one more streams comprising anaphtha stream, and then reforming at least a portion the naphtha streamto form a reformate comprising BTEX compounds, and then separating atleast a portion of the BTEX compounds from the reformate.
 6601. Themethod of claim 6597, further comprising hydrotreating at least some ofthe formation fluid, and then separating the hydrotreated mixture intoone more streams comprising a naphtha stream, and then reforming atleast a portion the naphtha stream to form a molecular hydrogen streamand a reformate comprising BTEX compounds, and then separating at leasta portion of the BTEX compounds from the reformate, and then utilizingthe molecular hydrogen stream to hydrotreat at least some of theformation fluid.
 6602. The method of claim 6597, further comprisinghydrotreating the formation fluid, and then separating the hydrotreatedformation fluid into one more streams comprising a naphtha stream, andthen reforming at least a portion the naphtha stream to form a reformatecomprising BTEX compounds, and then separating at least a portion of thereformate into two or more streams comprising a raffinate and a BTEXstream.
 6603. The method of claim 6597 wherein the formation fluid is atleast 200° C., and further comprising using heat in the formation fluidto hydrotreat at least a portion of the formation fluid.
 6604. Themethod of claim 6597, further comprising separating at least a portionof the formation fluid into one or more fractions wherein the one ormore fractions comprise a naphtha fraction, and further comprisingproviding the naphtha fraction to a catalytic reforming unit.
 6605. Themethod of claim 6597, further comprising separating at least a portionof the formation fluid into one or more fractions wherein the one ormore fractions comprise a BTEX compound generating fraction wherein theBTEX compound generating fraction comprises hydrocarbons, and furthercomprising providing the BTEX compound generating fraction to acatalytic reforming unit.
 6606. The method of claim 6597, wherein theheat provided from at least one heat source is transferred to theformation substantially by conduction.
 6607. The method of claim 6597,wherein the fluids are produced from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 6608. The method of claim 6597, wherein atleast one heat source comprises a heater.
 6609. A method of enhancingnaphthalene production from an oil shale formation, comprising:controlling at least one condition within at least a portion of theformation to enhance production of naphthalene in formation fluid,wherein the formation fluid is obtained by: providing heat from one ormore heat sources to at least a portion of the formation; allowing theheat to transfer from at least one or more heat sources to a selectedsection of the formation; and producing formation fluids from theformation.
 6610. The method of claim 6609, further comprising separatingat least a portion of the naphthalene from the produced fluids. 6611.The method of claim 6609 wherein controlling at least one condition inthe formation comprises controlling a fluid pressure within at least aportion of the formation.
 6612. The method of claim 6609 whereincontrolling at least one condition in the formation comprisescontrolling a temperature gradient within at least a portion of theformation.
 6613. The method of claim 6609 wherein controlling at leastone condition in the formation comprises controlling a temperaturewithin at least a portion of the formation.
 6614. The method of claim6609 wherein controlling at least one condition in the formationcomprises controlling a heating rate within at least a portion of theformation.
 6615. The method of claim 6609, further comprising separatingthe produced fluids into one or more fractions using distillation. 6616.The method of claim 6609, further comprising separating the producedfluids into one or more fractions using condensation.
 6617. The methodof claim 6609, further comprising separating the produced fluids intoone or more fractions wherein the one or more fractions comprise a heartcut, and further comprising providing the heart cut to an extractionunit, and separating at least some naphthalene from the heart cut. 6618.The method of claim 6609, further comprising separating the producedfluids into one or more fractions wherein the one or more fractionscomprise a naphthalene fraction, and further comprising providing thenaphthalene fraction to an extraction unit, and separating at least somenaphthalene from the naphthalene fraction.
 6619. The method of claim6609, wherein the heat provided from at least one heat source istransferred to the formation substantially by conduction.
 6620. Themethod of claim 6609, wherein the formation fluids are produced from theformation when a partial pressure of hydrogen in at least a portion theformation is at least about 0.5 bars absolute.
 6621. The method of claim6609, wherein at least one heat source comprises a heater.
 6622. Amethod of separating naphthalene from fluids produced from an oil shaleformation, comprising: separating naphthalene from the produced fluids,wherein the produced fluids are obtained by: providing heat from one ormore heat sources to at least a portion of the formation; allowing theheat to transfer from at least one or more heat sources to a selectedsection of the formation; and producing fluids from the formationwherein the produced fluids comprise naphthalene.
 6623. The method ofclaim 6622, further comprising controlling a fluid pressure within atleast a portion of the formation.
 6624. The method of claim 6622,further comprising controlling a temperature gradient within at least aportion of the formation.
 6625. The method of claim 6622, furthercomprising controlling a temperature within at least a portion of theformation.
 6626. The method of claim 6622, further comprisingcontrolling a heating rate within at least a portion of the formation.6627. The method of claim 6622 wherein separating at least somenaphthalene from the produced fluids further comprises separating theproduced fluids into one or more fractions using distillation.
 6628. Themethod of claim 6622 wherein separating at least some naphthalene fromthe produced fluids further comprises separating the produced fluidsinto one or more fractions using condensation.
 6629. The method of claim6622 wherein separating at least some naphthalene from the producedfluids further comprises separating the produced fluids into one or morefractions wherein the one or more fractions comprise a heart cut, andextracting at least a portion of the naphthalene from the heart cut.6630. The method of claim 6622 wherein separating at least somenaphthalene from the produced fluids further comprises removing anaphtha fraction from the produced fluids, and separating at least aportion of the naphthalene from the naphtha fraction.
 6631. The methodof claim 6622, wherein separating at least some naphthalene from theproduced fluids further comprises removing an naphthalene fraction fromthe produced fluids, and separating at least a portion of thenaphthalene from the naphthalene fraction.
 6632. The method of claim6622 wherein separating the naphthalene from the produced fluids furthercomprises removing naphthalene using distillation.
 6633. The method ofclaim 6622 wherein separating the naphthalene from the produced fluidsfurther comprises removing naphthalene using crystallization.
 6634. Themethod of claim 6622, further comprising removing at least a portion ofthe naphthalene prior to hydrotreating produced fluids.
 6635. The methodof claim 6622, further comprising removing at least a portion of thephenols prior to hydrotreating produced fluids, and wherein removing atleast the portion reduces an amount of molecular hydrogen required in ahydrotreating unit.
 6636. The method of claim 6622, wherein the heatprovided from at least one heat source is transferred to the formationsubstantially by conduction.
 6637. The method of claim 6622, wherein theformation fluids are produced from the formation when a partial pressureof hydrogen in at least a portion the formation is at least about 0.5bars absolute.
 6638. The method of claim 6622, wherein at least one heatsource comprises a heater.
 6639. A method of enhancing anthraceneproduction from an oil shale formation, comprising: controlling at leastone condition within at least a portion of the formation to enhanceproduction of anthracene in formation fluid, wherein the formation fluidis obtained by: providing heat from one or more heat sources to at leasta portion of the formation; allowing the heat to transfer from at leastone or more heat sources to a selected section of the formation; andproducing formation fluids from the formation.
 6640. The method of claim6639, further comprising separating at least a portion of the anthracenefrom the produced fluids.
 6641. The method of claim 6639 whereincontrolling at least one condition in the formation comprisescontrolling a fluid pressure within at least a portion of the formation.6642. The method of claim 6639 wherein controlling at least onecondition in the formation comprises controlling a temperature gradientwithin at least a portion of the formation.
 6643. The method of claim6639 wherein controlling at least one condition in the formationcomprises controlling a temperature within at least a portion of theformation.
 6644. The method of claim 6639 wherein controlling at leastone condition in the formation comprises controlling a heating ratewithin at least a portion of the formation.
 6645. The method of claim6639, further comprising separating the produced fluids into one or morefractions using distillation.
 6646. The method of claim 6639, furthercomprising separating the produced fluids into one or more fractionsusing condensation.
 6647. The method of claim 6639, further comprisingseparating the produced fluids into one or more fractions wherein theone or more fractions comprise a heart cut, and further comprisingproviding the heart cut to an extraction unit, and separating at leastsome anthracene from the heart cut.
 6648. The method of claim 6639,further comprising separating the produced fluids into one or morefractions wherein the one or more fractions comprise a anthracenefraction, and further comprising providing the anthracene fraction to anextraction unit, and separating at least some anthracene from theanthracene fraction.
 6649. The method of claim 6639, wherein the heatprovided from at least one heat source is transferred to the formationsubstantially by conduction.
 6650. The method of claim 6639, wherein theformation fluids are produced from the formation when a partial pressureof hydrogen in at least a portion the formation is at least about 0.5bars absolute.
 6651. The method of claim 6639, wherein at least one heatsource comprises a heater.
 6652. A method of separating anthracene fromfluids produced from an oil shale formation, comprising: separatinganthracene from the produced fluids, wherein the produced fluids areobtained by: providing heat from one or more heat sources to at least aportion of the formation; allowing the heat to transfer from at leastone or more heat sources to a selected section of the formation; andproducing fluids from the formation wherein the produced fluids compriseanthracene.
 6653. The method of claim 6652, further comprisingcontrolling a fluid pressure within at least a portion of the formation.6654. The method of claim 6652, further comprising controlling atemperature gradient within at least a portion of the formation. 6655.The method of claim 6652, further comprising controlling a temperaturewithin at least a portion of the formation.
 6656. The method of claim6652, further comprising controlling a heating rate within at least aportion of the formation
 6657. The method of claim 6652, whereinseparating at least some anthracene from the produced fluids furthercomprises separating the produced fluids into one or more fractionsusing distillation.
 6658. The method of claim 6652, wherein separatingat least some anthracene from the produced fluids further comprisesseparating the produced fluids into one or more fractions usingcondensation.
 6659. The method of claim 6652, wherein separating atleast some anthracene from the produced fluids further comprisesseparating the produced fluids into one or more fractions wherein theone or more fractions comprise a heart cut, and extracting at least aportion of the anthracene from the heart cut.
 6660. The method of claim6652, wherein separating at least some anthracene from the producedfluids further comprises removing a naphtha fraction from the producedfluids, and separating at least a portion of the anthracene from thenaphtha fraction.
 6661. The method of claim 6652, wherein separating atleast some anthracene from the produced fluids further comprisesremoving an anthracene fraction from the produced fluids, and separatingat least a portion of the anthracene from the anthracene fraction. 6662.The method of claim 6652, wherein separating the anthracene from theproduced fluids further comprises removing anthracene usingdistillation.
 6663. The method of claim 6652, wherein separating theanthracene from the produced fluids further comprises removinganthracene using crystallization.
 6664. The method of claim 6652,wherein the heat provided from at least one heat source is transferredto the formation substantially by conduction.
 6665. The method of claim6652, wherein the fluids are produced from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 6666. The method of claim 6652, wherein atleast one heat source comprises a heater.
 6667. A method of separatingammonia from fluids produced from an oil shale formation, comprising:separating at least a portion of the ammonia from the produced fluid,wherein the produced fluids are obtained by: providing heat from one ormore heat sources to at least a portion of the formation; allowing theheat to transfer from at least one or more heat sources to a selectedsection of the formation; and producing fluids from the formation. 6668.The method of claim 6667 wherein the produced fluids are pyrolyzationfluids.
 6669. The method of claim 6667 wherein separating at least aportion of the ammonia from the produced fluids further comprisesproviding at least a portion of the produced fluids to a sour waterstripper.
 6670. The method of claim 6667 wherein separating at least aportion of the ammonia from the produced fluids further comprisesseparating the produced fluids into one or more fractions, and providingat least a portion of the one or more fractions to a stripping unit.6671. The method of claim 6667, further comprising using at least aportion of the separated ammonia to generate ammonium sulfate.
 6672. Themethod of claim 6667, further comprising using at least a portion of theseparated ammonia to generate urea.
 6673. The method of claim 6667wherein the produced fluids comprise carbon dioxide, and furthercomprising separating the carbon dioxide from the produced fluids, andreacting the carbon dioxide with at least some ammonia to form urea.6674. The method of claim 6667 wherein the produced fluids comprisehydrogen sulfide, and further comprising separating the hydrogen sulfidefrom the produced fluids, converting at least some hydrogen sulfide intosulfuric acid, and reacting at lest some sulfuric acid with at leasesome ammonia to form ammonium sulfate.
 6675. The method of claim 6667wherein the produced fluids further comprise hydrogen sulfide, andfurther comprising separating at least a portion of the hydrogen sulfidefrom the produced fluids, and converting at least some hydrogen sulfideinto sulfuric acid.
 6676. The method of claim 6667, further comprisinggenerating ammonium bicarbonate using separated ammonia.
 6677. Themethod of claim 6667, further comprising providing separated ammonia toa fluid comprising carbon dioxide to generate ammonium bicarbonate.6678. The method of claim 6667, further comprising providing separatedammonia to at least some synthesis gas to generate ammonium bicarbonate.6679. The method of claim 6667, wherein the heat provided from at leastone heat source is transferred to the formation substantially byconduction.
 6680. The method of claim 6667, wherein the fluids areproduced from the formation when a partial pressure of hydrogen in atleast a portion the formation is at least about 0.5 bars absolute. 6681.The method of claim 6667, wherein at least one heat source comprises aheater.
 6682. A method of generating ammonia from fluids produced froman oil shale formation, comprising: hydrotreating at least a portion ofthe produced fluids to generate ammonia wherein the produced fluids areobtained by: providing heat from one or more heat sources to at least aportion of the formation; allowing the heat to transfer from at leastone or more heat sources to a selected section of the formation; andproducing fluids from the formation.
 6683. The method of claim 6682wherein the produced fluids are pyrolyzation fluids.
 6684. The method ofclaim 6682, further comprising separating at least a portion of theammonia from the hydrotreated fluids.
 6685. The method of claim 6682,further comprising using at least a portion of the ammonia to generateammonium sulfate.
 6686. The method of claim 6682, further comprisingusing at least a portion of the ammonia to generate urea.
 6687. Themethod of claim 6682 wherein the produced fluids further comprise carbondioxide, and further comprising separating at least a portion of thecarbon dioxide from the produced fluids, and reacting at least theportion of the carbon dioxide with at least a portion of ammonia to formurea.
 6688. The method of claim 6682 wherein the produced fluids furthercomprise hydrogen sulfide, and further comprising separating at least aportion of the hydrogen sulfide from the produced fluids, converting atleast some hydrogen sulfide into sulfuric acid, and reacting at leastsome sulfuric acid with at least a portion of the ammonia to formammonium sulfate.
 6689. The method of claim 6682 wherein the producedfluids further comprise hydrogen sulfide, and further comprisingseparating at least a portion of the hydrogen sulfide from the producedfluids, and converting at least some hydrogen sulfide into sulfuricacid.
 6690. The method of claim 6682, further comprising generatingammonium bicarbonate using at least a portion of the ammonia.
 6691. Themethod of claim 6682, further comprising providing at least a portion ofthe ammonia to a fluid comprising carbon dioxide to generate ammoniumbicarbonate.
 6692. The method of claim 6682, further comprisingproviding at least a portion of the ammonia to at least some synthesisgas to generate ammonium bicarbonate
 6693. The method of claim 6682,wherein the heat provided from at least one heat source is transferredto the formation substantially by conduction.
 6694. The method of claim6682, wherein the fluids are produced from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 6695. The method of claim 6682, wherein atleast one heat source comprises a heater.
 6696. A method of enhancingpyridines production from an oil shale formation, comprising:controlling at least one condition within at least a portion of theformation to enhance production of pyridines in formation fluid, whereinthe formation fluid is obtained by: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from at least one or more heat sources to a selected section ofthe formation; and producing formation fluids from the formation. 6697.The method of claim 6696, further comprising separating at least aportion of the pyridines from the produced fluids.
 6698. The method ofclaim 6696 wherein controlling at least one condition in the formationcomprises controlling a fluid pressure within at least a portion of theformation.
 6699. The method of claim 6696 wherein controlling at leastone condition in the formation comprises controlling a temperaturegradient within at least a portion of the formation.
 6700. The method ofclaim 6696 wherein controlling at least one condition in the formationcomprises controlling a temperature within at least a portion of theformation.
 6701. The method of claim 6696 wherein controlling at leastone condition in the formation comprises controlling a heating ratewithin at least a portion of the formation.
 6702. The method of claim6696, further comprising separating the produced fluids into one or morefractions using distillation.
 6703. The method of claim 6696, furthercomprising separating the produced fluids into one or more fractionsusing condensation.
 6704. The method of claim 6696, further comprisingseparating the produced fluids into one or more fractions wherein theone or more fractions comprise a heart cut, and further comprisingproviding the heart cut to an extraction unit, and separating at leastsome pyridines from the heart cut.
 6705. The method of claim 6696,further comprising separating the produced fluids into one or morefractions wherein the one or more fractions comprise a pyridinesfraction, and further comprising providing the pyridines fraction to anextraction unit, and separating at least some pyridines from thepyridines fraction.
 6706. The method of claim 6696, wherein the heatprovided from at least one heat source is transferred to the formationsubstantially by conduction.
 6707. The method of claim 6696, wherein theformation fluids are produced from the formation when a partial pressureof hydrogen in at least a portion the formation is at least about 0.5bars absolute.
 6708. The method of claim 6696, wherein at least one heatsource comprises a heater.
 6709. A method of separating pyridines fromfluids produced from an oil shale formation, comprising: separatingpyridines from the produced fluids, wherein the produced fluids areobtained by: providing heat from one or more heat sources to at least aportion of the formation; allowing the heat to transfer from at leastone or more heat sources to a selected section of the formation; andproducing fluids from the formation wherein the produced fluids comprisepyridines.
 6710. The method of claim 6709, further comprisingcontrolling a fluid pressure within at least a portion of the formation.6711. The method of claim 6709, further comprising controlling atemperature gradient within at least a portion of the formation. 6712.The method of claim 6709, further comprising controlling a temperaturewithin at least a portion of the formation.
 6713. The method of claim6709, further comprising controlling a heating rate within at least aportion of the formation
 6714. The method of claim 6709 whereinseparating at least some pyridines from the produced fluids furthercomprises separating the produced fluids into one or more fractionsusing distillation.
 6715. The method of claim 6709 wherein separating atleast some pyridines from the produced fluids further comprisesseparating the produced fluids into one or more fractions usingcondensation.
 6716. The method of claim 6709 wherein separating at leastsome pyridines from the produced fluids further comprises separating theproduced fluids into one or more fractions wherein the one or morefractions comprise a heart cut, and extracting at least a portion of thepyridines from the heart cut.
 6717. The method of claim 6709 whereinseparating at least some pyridines from the produced fluids furthercomprises removing a naphtha fraction from the produced fluids, andseparating at least a portion of the pyridines from the naphthafraction.
 6718. The method of claim 6709, wherein separating at leastsome pyridines from the produced fluids further comprises removing anpyridines fraction from the produced fluids, and separating at least aportion of the pyridines from the pyridines fraction.
 6719. The methodof claim 6709, wherein separating the pyridines from the produced fluidsfurther comprises removing pyridines using distillation.
 6720. Themethod of claim 6709, wherein separating the pyridines from the producedfluids further comprises removing pyridines using crystallization. 6721.The method of claim 6709, wherein the heat provided from at least oneheat source is transferred to the formation substantially by conduction.6722. The method of claim 6709, wherein the fluids are produced from theformation when a partial pressure of hydrogen in at least a portion theformation is at least about 0.5 bars absolute.
 6723. The method of claim6709, wherein at least one heat source comprises a heater.
 6724. Amethod of enhancing pyrroles production from an oil shale formation,comprising: controlling at least one condition within at least a portionof the formation to enhance production of pyrroles in formation fluid,wherein the formation fluid is obtained by: providing heat from one ormore heat sources to at least a portion of the formation; allowing theheat to transfer from at least one or more heat sources to a selectedsection of the formation; and producing formation fluids from theformation.
 6725. The method of claim 6724, further comprising separatingat least a portion of the pyrroles from the produced fluids.
 6726. Themethod of claim 6724 wherein controlling at least one condition in theformation comprises controlling a fluid pressure within at least aportion of the formation.
 6727. The method of claim 6724 whereincontrolling at least one condition in the formation comprisescontrolling a temperature gradient within at least a portion of theformation.
 6728. The method of claim 6724 wherein controlling at leastone condition in the formation comprises controlling a temperaturewithin at least a portion of the formation.
 6729. The method of claim6724 wherein controlling at least one condition in the formationcomprises controlling a heating rate within at least a portion of theformation.
 6730. The method of claim 6724, further comprising separatingthe produced fluids into one or more fractions using distillation. 6731.The method of claim 6724, further comprising separating the producedfluids into one or more fractions using condensation.
 6732. The methodof claim 6724, further comprising separating the produced fluids intoone or more fractions wherein the one or more fractions comprise a heartcut, and further comprising providing the heart cut to an extractionunit, and separating at least some pyrroles from the heart cut. 6733.The method of claim 6724, further comprising separating the producedfluids into one or more fractions wherein the one or more fractionscomprise a pyrroles fraction, and further comprising providing thepyrroles fraction to an extraction unit, and separating at least somepyrroles from the pyrroles fraction.
 6734. The method of claim 6724,wherein the heat provided from at least one heat source is transferredto the formation substantially by conduction.
 6735. The method of claim6724, wherein the formation fluids are produced from the formation whena partial pressure of hydrogen in at least a portion the formation is atleast about 0.5 bars absolute.
 6736. The method of claim 6724, whereinat least one heat source comprises a heater.
 6737. A method ofseparating pyrroles from fluids produced from an oil shale formation,comprising: separating pyrroles from the produced fluids, wherein theproduced fluids are obtained by: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from at least one or more heat sources to a selected section ofthe formation; and producing fluids from the formation wherein theproduced fluids comprise pyrroles.
 6738. The method of claim 6737,further comprising controlling a fluid pressure within at least aportion of the formation.
 6739. The method of claim 6737, furthercomprising controlling a temperature gradient within at least a portionof the formation.
 6740. The method of claim 6737, further comprisingcontrolling a temperature within at least a portion of the formation.6741. The method of claim 6737, further comprising controlling a heatingrate within at least a portion of the formation
 6742. The method ofclaim 6737 wherein separating at least some pyrroles from the producedfluids further comprises separating the produced fluids into one or morefractions using distillation.
 6743. The method of claim 6737 whereinseparating at least some pyrroles from the produced fluids furthercomprises separating the produced fluids into one or more fractionsusing condensation.
 6744. The method of claim 6737 wherein separating atleast some pyrroles from the produced fluids further comprisesseparating the produced fluids into one or more fractions wherein theone or more fractions comprise a heart cut, and extracting at least aportion of the pyrroles from the heart cut.
 6745. The method of claim6737 wherein separating at least some pyrroles from the produced fluidsfurther comprises removing a naphtha fraction from the produced fluids,and separating at least a portion of the pyrroles from the naphthafraction.
 6746. The method of claim 6737, wherein separating at leastsome pyrroles from the produced fluids further comprises removing anpyrroles fraction from the produced fluids, and separating at least aportion of the pyrroles from the pyrroles fraction.
 6747. The method ofclaim 6737, wherein separating the pyrroles from the produced fluidsfurther comprises removing pyrroles using distillation.
 6748. The methodof claim 6737, wherein separating the pyrroles from the produced fluidsfurther comprises removing pyrroles using crystallization.
 6749. Themethod of claim 6737, wherein the heat provided from at least one heatsource is transferred to the formation substantially by conduction.6750. The method of claim 6737, wherein the fluids are produced from theformation when a partial pressure of hydrogen in at least a portion theformation is at least about 0.5 bars absolute.
 6751. The method of claim6737, wherein at least one heat source comprises a heater.
 6752. Amethod of enhancing thiophenes production from an oil shale formation,comprising: controlling at least one condition within at least a portionof the formation to enhance production of thiophenes in formation fluid,wherein the formation fluid is obtained by: providing heat from one ormore heat sources to at least a portion of the formation; allowing theheat to transfer from at least one or more heat sources to a selectedsection of the formation; and producing formation fluids from theformation.
 6753. The method of claim 6752, further comprising separatingat least a portion of the thiophenes from the produced fluids.
 6754. Themethod of claim 6752 wherein controlling at least one condition in theformation comprises controlling a fluid pressure within at least aportion of the formation.
 6755. The method of claim 6752 whereincontrolling at least one condition in the formation comprisescontrolling a temperature gradient within at least a portion of theformation.
 6756. The method of claim 6752 wherein controlling at leastone condition in the formation comprises controlling a temperaturewithin at least a portion of the formation.
 6757. The method of claim6752 wherein controlling at least one condition in the formationcomprises controlling a heating rate within at least a portion of theformation.
 6758. The method of claim 6752, further comprising separatingthe produced fluids into one or more fractions using distillation. 6759.The method of claim 6752, further comprising separating the producedfluids into one or more fractions using condensation.
 6760. The methodof claim 6752, further comprising separating the produced fluids intoone or more fractions wherein the one or more fractions comprise a heartcut, and further comprising providing the heart cut to an extractionunit, and separating at least some thiophenes from the heart cut. 6761.The method of claim 6752, further comprising separating the producedfluids into one or more fractions wherein the one or more fractionscomprise a thiophenes fraction, and further comprising providing thethiophenes fraction to an extraction unit, and separating at least somethiophenes from the thiophenes fraction.
 6762. The method of claim 6752,wherein the heat provided from at least one heat source is transferredto the formation substantially by conduction.
 6763. The method of claim6752, wherein the formation fluids are produced from the formation whena partial pressure of hydrogen in at least a portion the formation is atleast about 0.5 bars absolute.
 6764. The method of claim 6752, whereinat least one heat source comprises a heater.
 6765. A method ofseparating thiophenes from fluids produced from an oil shale formation,comprising: separating thiophenes from the produced fluids, wherein theproduced fluids are obtained by: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from at least one or more heat sources to a selected section ofthe formation; and producing fluids from the formation wherein theproduced fluids comprise thiophenes.
 6766. The method of claim 6765,further comprising controlling a fluid pressure within at least aportion of the formation.
 6767. The method of claim 6765, furthercomprising controlling a temperature gradient within at least a portionof the formation.
 6768. The method of claim 6765, further comprisingcontrolling a temperature within at least a portion of the formation.6769. The method of claim 6765, further comprising controlling a heatingrate within at least a portion of the formation
 6770. The method ofclaim 6765 wherein separating at least some thiophenes from the producedfluids further comprises separating the produced fluids into one or morefractions using distillation.
 6771. The method of claim 6765 whereinseparating at least some thiophenes from the produced fluids furthercomprises separating the produced fluids into one or more fractionsusing condensation.
 6772. The method of claim 6765 wherein separating atleast some thiophenes from the produced fluids further comprisesseparating the produced fluids into one or more fractions wherein theone or more fractions comprise a heart cut, and extracting at least aportion of the thiophenes from the heart cut.
 6773. The method of claim6765 wherein separating at least some thiophenes from the producedfluids further comprises removing a naphtha fraction from the producedfluids, and separating at least a portion of the thiophenes from thenaphtha fraction.
 6774. The method of claim 6765 wherein separating atleast some thiophenes from the produced fluids further comprisesremoving an thiophenes fraction from the produced fluids, and separatingat least a portion of the thiophenes from the thiophenes fraction. 6775.The method of claim 6765 wherein separating the thiophenes from theproduced fluids further comprises removing thiophenes usingdistillation.
 6776. The method of claim 6765 wherein separating thethiophenes from the produced fluids further comprises removingthiophenes using crystallization.
 6777. The method of claim 6752,wherein the heat provided from at least one heat source is transferredto the formation substantially by conduction.
 6778. The method of claim6752, wherein the fluids are produced from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 6779. The method of claim 6752, wherein atleast one heat source comprises a heater.
 6780. A method of treating anoil shale formation comprising: providing a barrier to at least aportion of the formation to inhibit migration of fluids into or out of atreatment area of the formation; providing heat from one or more heatsources to the treatment area; allowing the heat to transfer from thetreatment area to a selected section of the formation; and producingfluids from the formation.
 6781. The method of claim 6780, wherein theheat provided from at least one of the one or more heat sources istransferred to at least a portion of the formation substantially byconduction.
 6782. The method of claim 6780, wherein the fluids areproduced from the formation when a partial pressure of hydrogen in atleast a portion the formation is at least about 0.5 bars absolute. 6783.The method of claim 6780, wherein at least one of the one or more of theheat sources comprises a heater.
 6784. The method of claim 6780, furthercomprising hydraulically isolating the treatment area from a surroundingportion of the formation.
 6785. The method of claim 6780, furthercomprising pyrolyzing at least a portion of hydrocarbon containingmaterial within the treatment area.
 6786. The method of claim 6780,further comprising generating synthesis gas in at least a portion of thetreatment area.
 6787. The method of claim 6780, further comprisingcontrolling a pressure within the treatment area.
 6788. The method ofclaim 6780, further comprising controlling a temperature within thetreatment area.
 6789. The method of claim 6780, further comprisingcontrolling a heating rate within the treatment area.
 6790. The methodof claim 6780, further comprising controlling an amount of fluid removedfrom the treatment area.
 6791. The method of claim 6780, wherein atleast section of the barrier comprises one or more sulfur wells. 6792.The method of claim 6780, wherein at least section of the barriercomprises one or more dewatering wells.
 6793. The method of claim 6780,wherein at least section of the barrier comprises one or more injectionwells and one or more dewatering wells.
 6794. The method of claim 6780,wherein providing a barrier comprises: providing a circulating fluid tothe a portion of the formation surrounding the treatment area; andremoving the circulating fluid proximate the treatment area.
 6795. Themethod of claim 6780, wherein at least section of the barrier comprisesa ground cover on a surface of the earth.
 6796. The method of claim6795, wherein at least section of the ground cover is sealed to asurface of the earth.
 6797. The method of claim 6780, further comprisinginhibiting a release of formation fluid to the earth's atmosphere with aground cover; and freezing at least a portion of the ground cover to asurface of the earth.
 6798. The method of claim 6780, further comprisinginhibiting a release of formation fluid to the earth's atmosphere. 6799.The method of claim 6780, further comprising inhibiting fluid seepagefrom a surface of the earth into the treatment area.
 6800. The method ofclaim 6780, wherein at least a section of the barrier is naturallyoccurring.
 6801. The method of claim 6780, wherein at least a section ofthe barrier comprises a low temperature zone.
 6802. The method of claim6780, wherein at least a section of the barrier comprises a frozen zone.6803. The method of claim 6780, wherein the barrier comprises aninstalled portion and a naturally occurring portion.
 6804. The method ofclaim 6780, further comprising: hydraulically isolating the treatmentarea from a surrounding portion of the formation; and maintaining afluid pressure within the treatment area at a pressure greater thanabout a fluid pressure within the surrounding portion of the formation.6805. The method of claim 6780, wherein at least a section of thebarrier comprises an impermeable section of the formation.
 6806. Themethod of claim 6780, wherein the barrier comprises a self-sealingportion.
 6807. The method of claim 6780, wherein the one or more heatsources are positioned at a distance greater than about 5 m from thebarrier.
 6808. The method of claim 6780, wherein at least one of the oneor more heat sources is positioned at a distance less than about 1.5 mfrom the barrier.
 6809. The method of claim 6780, wherein at least aportion of the barrier comprises a low temperature zone, and furthercomprising lowering a temperature within the low temperature zone to atemperature less than about a freezing temperature of water.
 6810. Themethod of claim 6780, wherein the barrier comprises a barrier well andfurther comprising positioning at least a portion of the barrier wellbelow a water table of the formation.
 6811. The method of claim 6780,wherein the treatment area comprises a first treatment area and a secondtreatment area, and further comprising: treating the first treatmentarea using a first treatment process; and treating the second treatmentarea using a second treatment process.
 6812. A method of treating an oilshale formation in situ, comprising: providing a refrigerant to aplurality of barrier wells placed in a portion of the formation;establishing a frozen barrier zone to inhibit migration of fluids intoor out of a treatment area; providing heat from one or more heat sourcesto the treatment area; allowing the heat to transfer from the treatmentarea to a selected section; and producing fluids from the formation.6813. The method of claim 6812, wherein the heat provided from at leastone of the one or more heat sources is transferred to at least a portionof the formation substantially by conduction.
 6814. The method of claim6812, wherein the fluids are produced from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 6815. The method of claim 6812, wherein atleast one of the one or more of the heat sources comprises a heater.6816. The method of claim 6812, further comprising controlling a fluidpressure within the treatment area;
 6817. The method of claim 6812,wherein the frozen barrier zone is proximate the treatment area of theformation
 6818. The method of claim 6812, further comprisinghydraulically isolating the treatment area from a surrounding portion ofthe formation.
 6819. The method of claim 6812, further comprisingthermally isolating the treatment area from a surrounding portion of theformation
 6820. The method of 6812, further comprising maintaining thefluid pressure above a hydrostatic pressure of the formation
 6821. Themethod of claim 6812, further comprising removing liquid water from atleast a portion of the treatment area.
 6822. The method of claim 6812,wherein the treatment area is below a water table of the formation.6823. The method of claim 6812, wherein at least one barrier well of theplurality of barrier wells comprises a corrosion inhibitor.
 6824. Themethod of claim 6812, wherein heating is initiated after formation ofthe frozen barrier zone.
 6825. The method of claim 6812, wherein therefrigerant comprises one or more hydrocarbons.
 6826. The method ofclaim 6812, wherein the refrigerant comprises propane.
 6827. The methodof claim 6812, wherein the refrigerant comprises isobutane.
 6828. Themethod of claim 6812, wherein the refrigerant comprises cyclopentane.6829. The method of claim 6812, wherein the refrigerant comprisesammonia.
 6830. The method of claim 6812, wherein the refrigerantcomprises an aqueous salt mixture.
 6831. The method of claim 6812,wherein the refrigerant comprises an organic acid salt.
 6832. The methodof claim 6812, wherein the refrigerant comprises a salt of an organicacid.
 6833. The method of claim 6812, wherein the refrigerant comprisesan organic acid.
 6834. The method of claim 6812, wherein the refrigeranthas a freezing point of less than about minus 60 degrees Celsius. 6835.The method of claim 6812, wherein the refrigerant comprises calciumchloride.
 6836. The method of claim 6812, wherein the refrigerantcomprises lithium chloride.
 6837. The method of claim 6812, wherein therefrigerant comprises liquid nitrogen.
 6838. The method of claim 6812,wherein the refrigerant is provided at a temperature of less than aboutminus 50 degrees Celsius.
 6839. The method of claim 6812, wherein therefrigerant comprises carbon dioxide.
 6840. The method of claim 6812,wherein at least one of the plurality of barrier wells is located alongstrike of a hydrocarbon containing portion of the formation.
 6841. Themethod of claim 6812, wherein at least one of the plurality of barrierwells is located along dip of a hydrocarbon containing portion of theformation.
 6842. The method of claim 6812, wherein the one or more heatsources are placed greater than about 5 m from a frozen barrier zone.6843. The method of claim 6812, wherein at least one of the one or moreheat sources is positioned less than about 1.5 m from a frozen barrierzone.
 6844. The method of claim 6812, wherein a distance between acenter of at least one barrier well and a center of at least oneadjacent barrier well is greater than about 2 m.
 6845. The method ofclaim 6812, further comprising desorbing methane from the formation.6846. The method of claim 6812, further comprising pyrolyzing at leastsome hydrocarbon containing material within the treatment area. 6847.The method of claim 6812, further comprising producing synthesis gasfrom at least a portion of the formation.
 6848. The method of claim6812, further comprising: providing a solvent to the treatment area suchthat the solvent dissolves a component in the treatment area; andremoving the solvent from the treatment area, wherein the removedsolvent comprises the component.
 6849. The method of claim 6812, furthercomprising sequestering a compound in at least a portion of thetreatment area.
 6850. The method of claim 6812, further comprisingthawing at least a portion of the frozen barrier zone; and whereinmaterial in a thawed barrier zone area is substantially unaltered by theapplication of heat.
 6851. The method of claim 6812, wherein a locationof the frozen barrier zone has been selected using a flow rate ofgroundwater and wherein the selected groundwater flow rate is less thanabout 50 m/day.
 6852. The method of claim 6812, further comprisingproviding water to the frozen barrier zone.
 6853. The method of claim6812, further comprising positioning one or more monitoring wellsoutside the frozen barrier zone, and then providing a tracer to thetreatment area, and then monitoring for movement of the tracer at themonitoring wells.
 6854. The method of claim 6812, further comprising:positioning one or more monitoring wells outside the frozen barrierzone; then providing an acoustic pulse to the treatment area; and thenmonitoring for the acoustic pulse at the monitoring wells.
 6855. Themethod of claim 6812, wherein a fluid pressure within the treatment areacan be controlled at fluid pressures different from a fluid pressurethat exists in a surrounding portion of the formation.
 6856. The methodof claim 6812, wherein fluid pressure within an area at least partiallybounded by the frozen barrier zone can be controlled higher than, orlower than, hydrostatic pressures that exist in a surrounding portion ofthe formation.
 6857. The method of claim 6812, further comprisingcontrolling compositions of fluids produced from the formation bycontrolling the fluid pressure within an area at least partially boundedby the frozen barrier zone.
 6858. The method of claim 6812, wherein aportion of at least one of the plurality of barrier wells is positionedbelow a water table of the formation.
 6859. A method of treating an oilshale formation comprising: providing a refrigerant to one or morebarrier wells placed in a portion of the formation; establishing a lowtemperature zone proximate a treatment area of the formation; providingheat from one or more heat sources to a treatment area of the formation;allowing the heat to transfer from the treatment area to a selectedsection of the formation; and producing fluids from the formation. 6860.The method of claim 6859, further comprising forming a frozen barrierzone within the low temperature zone, wherein the frozen barrier zonehydraulically isolates the treatment area from a surrounding portion ofthe formation.
 6861. The method of claim 6859, further comprisingforming a frozen barrier zone within the low temperature zone, andwherein fluid pressure within an area at least partially bounded by thefrozen barrier zone can be controlled at different fluid pressures fromthe fluid pressures that exist outside of the frozen barrier zone. 6862.The method of claim 6859, further comprising forming a frozen barrierzone within the low temperature zone, and wherein fluid pressure withinan area at least partially bounded by the frozen barrier zone can becontrolled higher than, or lower than, hydrostatic pressures that existoutside of the frozen barrier zone.
 6863. The method of claim 6859,further comprising forming a frozen barrier zone within the lowtemperature zone, and wherein fluid pressure within an area at leastpartially bounded by the frozen barrier zone can be controlled higherthan, or lower than, hydrostatic pressures that exist outside of thefrozen barrier zone, and further comprising controlling compositions offluids produced from the formation by controlling the fluid pressurewithin the area at least partially bounded by the frozen barrier zone.6864. The method of claim 6859, further comprising thawing at least aportion of the low temperature zone, wherein material within the thawedportion is substantially unaltered by the application of heat such thatthe structural integrity of the oil shale formation is substantiallymaintained.
 6865. The method of claim 6859, wherein an inner boundary ofthe low temperature zone is determined by monitoring a pressure waveusing one or more piezometers.
 6866. The method of claim 6859, furthercomprising controlling a fluid pressure within the treatment area at apressure less than about a formation fracture pressure.
 6867. The methodof claim 6859, further comprising positioning one or more monitoringwells outside the frozen barrier zone, and then providing an acousticpulse to the treatment area, and then monitoring for the acoustic pulseat the monitoring wells.
 6868. The method of claim 6859, furthercomprising positioning a segment of at least one of the one or morebarrier wells below a water table of the formation.
 6869. The method ofclaim 6859, further comprising positioning the one or more barrier wellsto establish a continuous low temperature zone.
 6870. The method ofclaim 6859, wherein the refrigerant comprises one or more hydrocarbons.6871. The method of claim 6859, wherein the refrigerant comprisespropane.
 6872. The method of claim 6859, wherein the refrigerantcomprises isobutane.
 6873. The method of claim 6859, wherein therefrigerant comprises cyclopentane.
 6874. The method of claim 6859,wherein the refrigerant comprises ammonia.
 6875. The method of claim6859, wherein the refrigerant comprises an aqueous salt mixture. 6876.The method of claim 6859, wherein the refrigerant comprises an organicacid salt.
 6877. The method of claim 6859, wherein the refrigerantcomprises a salt of an organic acid.
 6878. The method of claim 6859,wherein the refrigerant comprises an organic acid.
 6879. The method ofclaim 6859, wherein the refrigerant has a freezing point of less thanabout minus 60 degrees Celsius.
 6880. The method of claim 6859, whereinthe refrigerant is provided at a temperature of less than about minus 50degrees Celsius.
 6881. The method of claim 6859, wherein the refrigerantis provided at a temperature of less than about minus 25 degreesCelsius.
 6882. The method of claim 6859, wherein the refrigerantcomprises carbon dioxide.
 6883. The method of claim 6859, furthercomprising: cooling at least a portion of the refrigerant in anabsorption refrigeration unit; and providing a thermal energy source tothe absorption refrigeration unit.
 6884. The method of claim 6859,wherein the thermal energy source comprises water.
 6885. The method ofclaim 6859, wherein the thermal energy source comprises steam.
 6886. Themethod of claim 6859, wherein the thermal energy source comprises atleast a portion of the produced fluids.
 6887. The method of claim 6859,wherein the thermal energy source comprises exhaust gas.
 6888. A methodof treating an oil shale formation, comprising: inhibiting migration offluids into or out of a treatment area of the formation from asurrounding portion of the formation; providing heat from one or moreheat sources to at least a portion of the treatment area; allowing theheat to transfer from at least the portion to a selected section of theformation; and producing fluids from the formation.
 6889. The method ofclaim 6888, wherein the heat provided from at least one of the one ormore heat sources is transferred to at least a portion of the formationsubstantially by conduction.
 6890. The method of claim 6888, wherein thefluids are produced from the formation when a partial pressure ofhydrogen in at least a portion the formation is at least about 0.5 barsabsolute.
 6891. The method of claim 6888, wherein at least one of theone or more of the heat sources comprises a heater.
 6892. The method ofclaim 6888, further comprising providing a barrier to at least a portionof the formation.
 6893. The method of claim 6892, wherein at leastsection of the barrier comprises one or more sulfur wells.
 6894. Themethod of claim 6892, wherein at least section of the barrier comprisesone or more pumping wells.
 6895. The method of claim 6892, wherein atleast section of the barrier comprises one or more injection wells andone or more pumping wells.
 6896. The method of claim 6892, wherein atleast a section of the barrier is naturally occurring.
 6897. The methodof claim 6888, further comprises establishing a barrier in at least aportion of the formation, and wherein heat is provided after at least aportion of the barrier has been established.
 6898. The method of claim6888, further comprising establishing a barrier in at least a portion ofthe formation, and wherein heat is provided while at least a portion ofthe barrier is being established.
 6899. The method of claim 6888,further comprising providing a barrier to at least a portion of theformation, and wherein heat is provided before the barrier isestablished.
 6900. The method of claim 6888, further comprisingcontrolling an amount of fluid removed from the treatment area. 6901.The method of claim 6888, wherein isolating a treatment area from asurrounding portion of the formation comprises providing a lowtemperature zone to at least a portion of the formation.
 6902. Themethod of claim 6888, wherein isolating a treatment area from asurrounding portion of the formation comprises providing a frozenbarrier zone to at least a portion of the formation.
 6903. The method ofclaim 6888, wherein isolating a treatment area from a surroundingportion of the formation comprises providing a grout wall.
 6904. Themethod of claim 6888, further comprising inhibiting flow of water intoor out of at least a portion of a treatment area.
 6905. The method ofclaim 6888, further comprising: providing a material to the treatmentarea; and storing at least some of the material within the treatmentarea.
 6906. A method of treating an oil shale formation, comprising:providing a barrier to a portion of the formation, wherein the portionhas previously undergone an in situ conversion process; and inhibitingmigration of fluids into and out of the converted portion to asurrounding portion of the formation.
 6907. The method of claim 6906,wherein the barrier comprises a frozen barrier zone.
 6908. The method ofclaim 6906, wherein the barrier comprises a low temperature zone. 6909.The method of claim 6906, wherein the barrier comprises a sealingmineral phase.
 6910. The method of claim 6906, wherein the barriercomprises a sulfur barrier.
 6911. The method of claim 6906, wherein thecontaminant comprises a metal.
 6912. The method of claim 6906, whereinthe contaminant comprises organic residue.
 6913. A method of treating anoil shale formation, comprising: introducing a first fluid into at leasta portion of the formation, wherein the portion has previously undergonean in situ conversion process; producing a mixture of the first fluidand a second fluid from the formation; and providing at least a portionof the mixture to an energy producing unit.
 6914. The method of claim6913, wherein the first fluid is selected to recover heat from theformation.
 6915. The method of claim 6913, wherein the first fluid isselected to recover heavy compounds from the formation.
 6916. The methodof claim 6913, wherein the first fluid is selected to recoverhydrocarbons from the formation.
 6917. The method of claim 6913, whereinthe mixture comprises an oxidizable heat recovery fluid.
 6918. Themethod of claim 6913, wherein producing the mixture remediates theportion of the formation by removing contaminants from the formation inthe mixture.
 6919. The method of claim 6913, wherein the first fluidcomprises a hydrocarbon fluid.
 6920. The method of claim 6913, whereinthe first fluid comprises methane.
 6921. The method of claim 6913,wherein the first fluid comprises ethane.
 6922. The method of claim6913, wherein the first fluid comprises molecular hydrogen.
 6923. Themethod of claim 6913, wherein the energy producing unit comprises aturbine, and generating electricity by passing mixture through theenergy producing unit.
 6924. The method of claim 6913, furthercomprising combusting mixture within the energy producing unit. 6925.The method of claim 6913, further comprising inhibiting spread of themixture from the portion of the formation with a barrier.
 6926. A methodof treating an oil shale formation, comprising: providing a first fluidto at least a portion of a treatment area, wherein the treatment areaincludes one or more components; producing a fluid from the formationwherein the produced fluid comprises first fluid and at least some ofthe one or more components; and wherein the treatment area is obtainedby providing heat from heat sources to a portion of an oil shaleformation to convert a portion of hydrocarbons to desired products andremoving a portion of the desired hydrocarbons from the formation. 6927.The method of claim 6926, wherein the first fluid comprises water. 6928.The method of claim 6926, wherein the first fluid comprises carbondioxide.
 6929. The method of claim 6926, wherein the first fluidcomprises steam.
 6930. The method of claim 6926, wherein the first fluidcomprises air.
 6931. The method of claim 6926, wherein the first fluidcomprises a combustible gas.
 6932. The method of claim 6926, wherein thefirst fluid comprises hydrocarbons.
 6933. The method of claim 6926,wherein the first fluid comprises methane.
 6934. The method of claim6926, wherein the first fluid comprises ethane.
 6935. The method ofclaim 6926, wherein the first fluid comprises molecular hydrogen. 6936.The method of claim 6926, wherein the first fluid comprises propane.6937. The method of claim 6926, further comprising reacting a portion ofthe contaminants with the first fluid.
 6938. The method of claim 6926,further comprising providing at least a portion of the produced fluid toan energy generating unit to generate electricity.
 6939. The method ofclaim 6926, further comprising providing at least a portion of theproduced fluid to a combustor.
 6940. The method of claim 6926, wherein afrozen barrier defines at least a segment of a barrier within theformation, allowing a portion of the frozen barrier to thaw prior toproviding the first fluid to the treatment area, and providing at leastsome of the first fluid into the thawed portion of the barrier. 6941.The method of claim 6926, wherein a volume of first fluid provided tothe treatment area is greater than about one pore volume of thetreatment area.
 6942. The method of claim 6926, further comprisingseparating contaminants from the first fluid.
 6943. A method ofrecovering thermal energy from a heated oil shale formation, comprising:injecting a heat recovery fluid into a heated portion of the formation;allowing heat from the portion of the formation to transfer to the heatrecovery fluid; and producing fluids from the formation.
 6944. Themethod of claim 6943, wherein the heat recovery fluid comprises water.6945. The method of claim 6943, wherein the heat recovery fluidcomprises saline water.
 6946. The method of claim 6943, wherein the heatrecovery fluid comprises non-potable water.
 6947. The method of claim6943, wherein the heat recovery fluid comprises alkaline water. 6948.The method of claim 6943, wherein the heat recovery fluid compriseshydrocarbons.
 6949. The method of claim 6943, wherein the heat recoveryfluid comprises an inert gas.
 6950. The method of claim 6943, whereinthe heat recovery fluid comprises carbon dioxide.
 6951. The method ofclaim 6943, wherein the heat recovery fluid comprises a product streamproduced by an in situ conversion process.
 6952. The method of claim6943, further comprising vaporizing at least some of the heat recoveryfluid.
 6953. The method of claim 6943, wherein an average temperature ofthe portion of the post treatment formation prior to injection of heatrecovery fluid is greater than about 300° C.
 6954. The method of claim6943, further comprising providing the heat recovery fluid to theformation through a heater well.
 6955. The method of claim 6943, whereinfluids are produced from one or more production wells in the formation.6956. The method of claim 6943, further comprising providing at leastsome of the produced fluids to a treatment process in a section of theformation.
 6957. The method of claim 6943, further comprising recoveringat least some of the heat from the produced fluids.
 6958. The method ofclaim 6943, further comprising providing at least some of the producedfluids to a power generating unit.
 6959. The method of claim 6943,further comprising providing at least some of the produced fluids to aheat exchange mechanism.
 6960. The method of claim 6943, furthercomprising providing at least some of the produced fluids to a steamcracking unit.
 6961. The method of claim 6943, further comprisingproviding at least some of the produced fluids to a hydrotreating unit.6962. The method of claim 6943, further comprising providing at leastsome of the produced fluids to a distillation column.
 6963. The methodof claim 6943, wherein the heat recovery fluid comprises carbon dioxide,and wherein at least some of the carbon dioxide is adsorbed onto thesurface of carbon in the formation.
 6964. The method of claim 6943,wherein the heat recovery fluid comprises carbon dioxide, and furthercomprising: allowing at least some hydrocarbons within the formation todesorb from the formation; and producing at least some of the desorbedhydrocarbons from the formation.
 6965. The method of claim 6943, furthercomprising providing at least some of the produced fluids to a treatmentprocess in a section of the formation.
 6966. The method of claim 6943,wherein the heat recovery fluid is saline water, and further comprising:providing carbon dioxide to the portion of the formation; andprecipitating carbonate compounds.
 6967. The method of claim 6943,further comprising reducing an average temperature of the formation to atemperature less than about an ambient boiling temperature of water at apost treatment pressure.
 6968. The method of claim 6943, wherein theproduced fluids comprise low molecular weight hydrocarbons.
 6969. Themethod of claim 6943, wherein the produced fluids comprise hydrocarbons.6970. The method of claim 6943, wherein the produced fluids compriseheat recovery fluid.
 6971. A method of treating an oil shale formation,comprising: providing heat from one or more heat sources to at least aportion of the formation; allowing the heat to transfer from the one ormore heat sources to a selected section of the formation; controlling atleast one condition within the selected section; producing a mixturefrom the formation; and wherein at least the one condition is controlledsuch that the mixture comprises a carbon dioxide emission level lessthan about a selected carbon dioxide emission level.
 6972. The method ofclaim 6971, wherein the heat provided from at least one heat source istransferred to at least a portion of the formation substantially byconduction.
 6973. The method of claim 6971, wherein the mixture isproduced from the formation when a partial pressure of hydrogen in atleast a portion the formation is at least about 0.5 bars absolute. 6974.The method of claim 6971, wherein at least one of the one or more of theheat sources comprises a heater.
 6975. The method of claim 6971, whereinthe selected carbon dioxide emission level is less than about 5.6×10⁻⁸kg CO₂ produced for every Joule of energy.
 6976. The method of claim6971, wherein the selected carbon dioxide emission level is less thanabout 1.6×10⁻⁸ kg CO₂ produced for every Joule of energy.
 6977. Themethod of claim 6971, wherein the selected carbon dioxide emission levelis less than about 1.6×10⁻¹⁰ kg CO₂ produced for every Joule of energy.6978. The method of claim 6971, further comprising blending the mixturewith a fluid to form a blended product comprising a carbon dioxideemission level less than about the selected baseline carbon dioxideemission level.
 6979. The method of claim 6971, wherein controllingconditions within a selected section comprises controlling a pressurewithin the selected section.
 6980. The method of claim 6971, whereincontrolling conditions within a selected section comprises controllingan average temperature within the selected section.
 6981. The method ofclaim 6971, wherein controlling conditions within a selected sectioncomprises controlling an average heating rate within the selectedsection.
 6982. A method for producing molecular hydrogen from an oilshale formation, comprising: providing heat from one or more heatsources to at least one portion of the formation such that carbondioxide production is minimized; allowing the heat to transfer from theone or more heat sources to a selected section of the formation;producing a mixture comprising molecular hydrogen from the formation;and controlling the heat from the one or more heat sources to enhanceproduction of molecular hydrogen.
 6983. The method of claim 6982,wherein the heat provided from at least one heat source is transferredto at least a portion of the formation substantially by conduction.6984. The method of claim 6982, wherein at least one of the one or moreof the heat sources comprises a heater.
 6985. The method of claim 6982,wherein the mixture is produced from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 6986. The method of claim 6982, whereincontrolling the heat comprises controlling a temperature proximate theproduction wellbore at or above a decomposition temperature of methane.6987. The method of claim 6982, wherein heat is generated by oxidizingmolecular hydrogen in at least one heat source.
 6988. The method ofclaim 6982, wherein heat is generated by electricity produced from windpower.
 6989. The method of claim 6982, wherein heat is generated fromelectrical power.
 6990. The method of claim 6982, wherein the heatsources form an array of heat sources.
 6991. The method of claim 6982,further comprising heating at least a portion of the selected section ofthe formation to greater than about 600° C.
 6992. The method of claim6982, wherein the produced mixture is produced from a productionwellbore, and further comprising controlling the heat from one or moreheat sources such that the temperature in the formation proximate theproduction wellbore is at least about 600° C.
 6993. The method of claim6982, wherein the produced mixture is produced from a productionwellbore, and further comprising heating at least a portion of theformation with a heater proximate the production wellbore.
 6994. Themethod of claim 6982, further comprising recycling at least a portion ofthe produced molecular hydrogen into the formation.
 6995. The method ofclaim 6982, wherein the produced mixture comprises methane, and furthercomprising oxidizing at least a portion of the methane to provide heatto the formation.
 6996. The method of claim 6982, wherein controllingthe heat comprises maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 6997. The method of claim 6982,wherein the one or more heat sources comprise one or more electricalheaters powered by a fuel cell, and wherein at least a portion of themolecular hydrogen in the produced mixture is used in the fuel cell.6998. The method of claim 6982, further comprising controlling apressure within at least a majority of the selected section of theformation.
 6999. The method of claim 6982, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 3° C. per day during pyrolysis.
 7000. Themethod of claim 6982, wherein allowing the heat to transfer from the oneor more heat sources to the selected section comprises transferring heatsubstantially by conduction.
 7001. The method of claim 6982, wherein atleast 50% by volume of the produced mixture comprises molecularhydrogen.
 7002. The method of claim 6982, wherein less than about3.3×10⁻⁸ kg CO₂ is produced for every Joule of energy in the producedmixture.
 7003. The method of claim 6982, wherein less than about1.6×10⁻¹⁰ kg CO₂ is produced for every Joule of energy in the producedmixture.
 7004. The method of claim 6982, wherein less than about3.3×10⁻¹⁰ kg CO₂ is produced for every Joule of energy in the producedmixture.
 7005. The method of claim 6982, wherein the produced mixture isproduced from a production wellbore, and further comprising controllingthe heat from one or more heat sources such that the temperature in theformation proximate the production wellbore is at least about 500° C.7006. The method of claim 6982, wherein the produced mixture comprisesmethane and molecular hydrogen, and further comprising: separating atleast a portion of the molecular hydrogen from the produced mixture; andproviding at least a portion of the separated mixture to at least one ofthe one or more heat sources for use as fuel.
 7007. The method of claim6982, wherein the produced mixture comprises methane and molecularhydrogen, and further comprising: separating at least a portion of themolecular hydrogen from the produced mixture; and providing at leastsome of the molecular hydrogen to a fuel cell to generate electricity.7008. A method for producing methane from an oil shale formation in situwhile minimizing production of CO2, comprising: providing heat from oneor more heat sources to at least one portion of the formation such thatCO₂ production is minimized; allowing the heat to transfer from the oneor more heat sources to a selected section of the formation; producing amixture comprising methane from the formation; and controlling the heatfrom the one or more heat sources to enhance production of methane.7009. The method of claim 7008, wherein the heat provided from at leastone of the one or more heat source is transferred to at least a portionof the formation substantially by conduction.
 7010. The method of claim7008, wherein at least one of the one or more of the heat sourcescomprises a heater.
 7011. The method of claim 7008, wherein controllingthe heat comprises controlling a temperature proximate the productionwellbore at or above a decomposition temperature of ethane.
 7012. Themethod of claim 7008, wherein heat is generated by oxidizing methane inat least one heat source.
 7013. The method of claim 7008, wherein heatis generated by electricity produced from wind power.
 7014. The methodof claim 7008, wherein heat is generated from electrical power. 7015.The method of claim 7008, wherein the heat sources form an array of heatsources.
 7016. The method of claim 7008, further comprising heating atleast a portion of the selected section of the formation to greater thanabout 400° C.
 7017. The method of claim 7008, wherein the producedmixture is produced from a production wellbore, and further comprisingcontrolling the heat from one or more heat sources such that thetemperature in the formation proximate the production wellbore is atleast about 400° C.
 7018. The method of claim 7008, wherein the producedmixture is produced from a production wellbore, and further comprisingheating at least a portion of the formation with a heater proximate theproduction wellbore.
 7019. The method of claim 7008, further comprisingrecycling at least a portion of the produced methane into the formation.7020. The method of claim 7008, wherein the produced mixture comprisesmethane, and further comprising oxidizing at least a portion of themethane to provide heat to the formation.
 7021. The method of claim7008, wherein the one or more heat sources comprise at least two heatsources, and wherein superposition of heat from at least the two heatsources pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 7022. The method of claim 7008, wherein controllingthe heat comprises maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 7023. The method of claim 7008,wherein the one or more heat sources comprise one or more electricalheaters powered by a fuel cell, and wherein at least a portion of themolecular hydrogen in the produced mixture is used in the fuel cell.7024. The method of claim 7008, further comprising controlling apressure within at least a majority of the selected section of theformation.
 7025. The method of claim 7008, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 3° C. per day during pyrolysis.
 7026. Themethod of claim 7008, wherein allowing the heat to transfer from the oneor more heat sources to the selected section comprises transferring heatsubstantially by conduction.
 7027. The method of claim 7008, whereinless than about 8.4×10⁻⁸ kg CO₂ is produced for every Joule of energy inthe produced mixture.
 7028. The method of claim 7008, wherein less thanabout 7.4×10⁻⁸ kg CO₂ is produced for every Joule of energy in theproduced mixture.
 7029. The method of claim 7008, wherein less thanabout 5.6×10⁻⁸ kg CO₂ is produced for every Joule of energy in theproduced mixture.
 7030. A method for upgrading hydrocarbons in an oilshale formation, comprising: providing heat from one or more heatsources to a portion of the formation; allowing the heat to transferfrom the first portion to a selected section of the formation; providinghydrocarbons to the selected section, and producing a mixture from theformation, wherein the mixture comprises hydrocarbons that were providedto the selected section and upgraded in the formation.
 7031. The methodof claim 7030, wherein the mixture is produced from the formation when apartial pressure of hydrogen in at least a portion the formation is atleast about 0.5 bars absolute.
 7032. The method of claim 7030, whereinthe heat provided from at least one heat source is transferred to atleast a portion of the formation substantially by conduction.
 7033. Themethod of claim 7030, wherein at least one of the one or more of theheat sources comprises a heater.
 7034. The method of claim 7030, whereinthe provided hydrocarbons comprise heavy hydrocarbons.
 7035. The methodof claim 7030, wherein the provided hydrocarbons comprise naphtha. 7036.The method of claim 7030, wherein the provided hydrocarbons compriseasphaltenes.
 7037. The method of claim 7030, wherein the providedhydrocarbons comprise crude oil.
 7038. The method of claim 7030, whereinthe provided hydrocarbons comprise surface mined tar from relativelypermeable formations.
 7039. The method of claim 7030 wherein theprovided hydrocarbons comprise an emulsion produced from a relativelypermeable formation, and further comprising providing the producedemulsion to the first portion after a temperature in the selectedsection is greater than about a pyrolysis temperature.
 7040. The methodof claim 7030, further comprising providing steam to the selectedsection.
 7041. The method of claim 7030, further comprising: producingformation fluids from the formation; separating the produced formationfluids into one or more components; and wherein the providedhydrocarbons comprise at least one of the one or more components. 7042.The method of claim 7030, further comprising: providing steam to theselected section, wherein the provided hydrocarbons are mixed with thesteam; and controlling an amount of steam such that a residence time ofthe provided hydrocarbons within the selected section is controlled.7043. The method of claim 7030, wherein the produced mixture comprisesupgraded hydrocarbons, and further comprising controlling a residencetime of the provided hydrocarbons within the selected section to controla molecular weight distribution within the upgraded hydrocarbons. 7044.The method of claim 7030, wherein the produced mixture comprisesupgraded hydrocarbons, and further comprising controlling a residencetime of the provided hydrocarbons in the selected section to control anAPI gravity of the upgraded hydrocarbons.
 7045. The method of claim7030, further comprising steam cracking in at least a portion of theselected section.
 7046. The method of claim 7030, wherein the providedhydrocarbons are produced from a second portion of the formation. 7047.The method of claim 7030, further comprising allowing some of theprovided hydrocarbons to crack in the formation to generate upgradedhydrocarbons.
 7048. The method of claim 7030, further comprisingcontrolling a temperature of the first portion of the formation bycontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 7049. The method of claim 7030,further comprising controlling a pressure within at least a majority ofthe selected section of the formation.
 7050. The method of claim 7030,wherein a temperature in the first portion is greater than about apyrolysis temperature.
 7051. The method of claim 7030, furthercomprising: controlling the heat such that a temperature of the firstportion is greater than about a pyrolysis temperature of hydrocarbons;and producing at least some of the provided hydrocarbons from the firstportion of the formation.
 7052. The method of claim 7030, furthercomprising producing at least some of the provided hydrocarbons from asecond portion of the formation.
 7053. The method of claim 7030, furthercomprising: controlling the heat such that a temperature of a secondportion is less than about a pyrolysis temperature of hydrocarbons; andproducing at least some of the provided hydrocarbons from the secondportion of the formation.
 7054. The method of claim 7030, furthercomprising producing at least some of the provided hydrocarbons from asecond portion of the formation and wherein a temperature of the secondportion is about an ambient temperature of the formation.
 7055. Themethod of claim 7030, wherein the upgraded hydrocarbons are producedfrom a production well and wherein the heat is controlled such that theupgraded hydrocarbons can be produced from the formation as a vapor.7056. A method for producing methane from an oil shale formation insitu, comprising: providing heat from one or more heat sources to atleast one portion of the formation; allowing the heat to transfer fromthe one or more heat sources to a selected section of the formation;providing hydrocarbon fluids to at least the selected section of theformation; and producing mixture comprising methane from the formation.7057. The method of claim 7056, wherein the heat provided from at leastone heat source is transferred to at least a portion of the formationsubstantially by conduction.
 7058. The method of claim 7056, wherein atleast one of the one or more of the heat sources comprises a heater.7059. The method of claim 7056, further comprising controlling heat fromat least one of the heat sources to enhance production of methane fromthe hydrocarbon fluids.
 7060. The method of claim 7056, furthercomprising controlling a temperature within at least a selected sectionin a range to from greater than about 400° C. to less than about 600° C.7061. The method of claim 7056, further comprising cooling the mixtureto inhibit further reaction of the methane.
 7062. The method of claim7056, further comprising controlling at least some condition in theformation to enhance production of methane.
 7063. The method of claim7056, further comprising adding water to the formation.
 7064. The methodof claim 7056, further comprising separating at least a portion of themethane from the mixture and recycling at least some of the separatedmixture to the formation.
 7065. The method of claim 7056, furthercomprising cracking the hydrocarbon fluids to form methane.
 7066. Themethod of claim 7056, wherein the mixture is produced from the formationthrough a production well, and wherein the heat is controlled such thatthe mixture can be produced from the formation as a vapor.
 7067. Themethod of claim 7056, wherein the mixture is produced from the formationthrough a production well, and further comprising heating a wellbore ofthe production well to inhibit condensation of the mixture within thewellbore.
 7068. The method of claim 7056, wherein the mixture isproduced from the formation through a production well, wherein awellbore of the production well comprises a heater element configured toheat the formation adjacent to the wellbore, and further comprisingheating the formation with the heater element to produce the mixture.7069. A method for hydrotreating a fluid in a heated formation in situ,comprising: providing heat from one or more heat sources to at least oneportion of the formation; allowing the heat to transfer from the one ormore heat sources to a selected section of the formation; providing afluid to the selected section; controlling a H₂ partial pressure in theselected section of the formation; hydrotreating at least some of thefluid in the selected section; and producing a mixture comprisinghydrotreated fluids from the formation.
 7070. The method of claim 7069,wherein the mixture is produced from the formation when a partialpressure of hydrogen in the selected section is at least about 0.5 barsabsolute.
 7071. The method of claim 7069, wherein the heat provided fromat least one of the one or more heat source is transferred to at least aportion of the formation substantially by conduction.
 7072. The methodof claim 7069, wherein at least one of the one or more of the heatsources comprises a heater.
 7073. The method of claim 7069, furthercomprising providing hydrogen to the selected section of the formation.7074. The method of claim 7069, further comprising controlling the heatsuch that a temperature within the selected section is in a range fromabout 200° C. to about 450° C.
 7075. The method of claim 7069, whereinthe provided fluid comprises an olefin.
 7076. The method of claim 7069,wherein the provided fluid comprises pitch.
 7077. The method of claim7069, wherein the provided fluid comprises oxygenated compounds. 7078.The method of claim 7069, wherein the provided fluid comprises sulfurcontaining compounds.
 7079. The method of claim 7069, wherein theprovided fluid comprises nitrogen containing compounds.
 7080. The methodof claim 7069, wherein the provided fluid comprises crude oil.
 7081. Themethod of claim 7069, wherein the provided fluid comprises syntheticcrude oil.
 7082. The method of claim 7069, wherein the produced mixturecomprises a hydrocarbon mixture.
 7083. The method of claim 7069, whereinthe produced mixture comprises less than about 1% by weight ammonia.7084. The method of claim 7069, wherein the produced mixture comprisesless than about 1% by weight hydrogen sulfide.
 7085. The method of claim7069, wherein the produced mixture comprises less than about 1%oxygenated compounds.
 7086. The method of claim 7069, further comprisingproducing the mixture from the formation through a production well,wherein the heating is controlled such that the mixture can be producedfrom the formation as a vapor.
 7087. A method for producing hydrocarbonsfrom a heated formation in situ, comprising: providing heat from one ormore heat sources to at least one portion of the formation; allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation such that at least some of the selected sectioncomprises a temperature profile; providing a hydrocarbon mixture to theselected section; separating the hydrocarbon mixture into one or moremixtures of components; and producing the one or more mixtures ofcomponents from one or more production wells.
 7088. The method of claim7087, wherein the heat provided from at least one of the one or moreheat source is transferred to at least a portion of the formationsubstantially by conduction.
 7089. The method of claim 7087, wherein theone or more of the heat sources comprise heaters.
 7090. The method ofclaim 7087, wherein at least one of the one or more mixtures is producedfrom the formation when a partial pressure of hydrogen in at least aportion the formation is at least about 0.5 bars absolute.
 7091. Themethod of claim 7087, further comprising controlling a pressure withinat least a majority of the selected section.
 7092. The method of claim7087, wherein the temperature profile extends horizontally through theformation.
 7093. The method of claim 7087, wherein the temperatureprofile extends vertically through the formation.
 7094. The method ofclaim 7087, wherein the selected section comprises a spent formation.7095. The method of claim 7087, wherein the production well comprises aplurality of production wells placed at various distances from at leastone of the one or more heat sources along the temperature gradient zone.7096. The method of claim 7087, wherein the production well comprises afirst production well and a second production well, further comprising:positioning the first production well at a first distance from a heatsource of the one or more heat sources; positioning the secondproduction well at a second distance from the heat source of the one ormore heat sources; producing a first component of the one or moreportions from the first production well; and producing a secondcomponent of the one or more portions from the second production well.7097. The method of claim 7087, further comprising heating a wellbore ofthe production well to inhibit condensation of at least the onecomponent within the wellbore.
 7098. The method of claim 7087, whereinthe one or more components comprise hydrocarbons.
 7099. The method ofclaim 7087, wherein separating the one or more components furthercomprises: producing a low molecular weight component of the one or morecomponents from the formation; allowing a high molecular weightcomponent of the one or more components to remain within the formation;providing additional heat to the formation; and producing at least someof the high molecular weight component.
 7100. The method of claim 7087,further comprising producing at least the one component from theformation through a production well, wherein the heating is controlledsuch that the mixture can be produced from the formation as a vapor.7101. A method of utilizing heat of a heated formation, comprising:placing a conduit in the formation,; allowing heat from the formation totransfer to at least a portion of the conduit; generating a region ofreaction in the conduit; allowing a material to flow through the regionof reaction; reacting at least some of the material in the region ofreaction; and producing a mixture from the conduit.
 7102. The method ofclaim 7101, wherein a conduit input is located separately from a conduitoutput
 7103. The method of claim 7101, wherein the conduit is configuredto inhibit contact between the material and the formation.
 7104. Themethod of claim 7101, wherein the conduit comprises a u-shaped conduit,and further comprising placing the u-shaped conduit within a heater wellin the heated formation.
 7105. The method of claim 7101, wherein thematerial comprises a first hydrocarbon and wherein the first hydrocarbonreacts to form a second hydrocarbon.
 7106. The method of claim 7101,wherein the material comprises water.
 7107. The method of claim 7101,wherein the produced mixture comprises hydrocarbons.
 7108. A method forstoring fluids within an oil shale formation, comprising: providing abarrier to a portion of the formation to form an in situ storage area,wherein at least a portion of the in situ storage area has previouslyundergone an in situ conversion process, and wherein migration of fluidsinto or out of the storage area is inhibited; providing a material tothe in situ storage area; storing at least some of the provided fluidswithin the in situ storage area; and wherein one or more conditions ofthe in situ storage area inhibits reaction within the material. 7109.The method of claim 7108, further comprising producing at least some ofthe stored material from the in situ storage area.
 7110. The method ofclaim 7108, further comprising producing at least some of the storedmaterial from the in situ storage area as a liquid.
 7111. The method ofclaim 7108, further comprising producing at least some of the storedmaterial from the in situ storage area as a gas.
 7112. The method ofclaim 7108, wherein the stored material is a solid, and furthercomprising: providing a solvent to the in situ storage area; allowing atleast a portion of the stored material to dissolve; and producing atleast some of the dissolved material from the in situ storage area.7113. The method of claim 7108, wherein the material comprises inorganiccompounds.
 7114. The method of claim 7108, wherein the materialcomprises organic compounds.
 7115. The method of claim 7108, wherein thematerial comprises hydrocarbons.
 7116. The method of claim 7108, whereinthe material comprises formation fluids
 7117. The method of claim 7108,wherein the material comprises synthesis gas.
 7118. The method of claim7108, wherein the material comprises a solid.
 7119. The method of claim7108, wherein the material comprises a liquid.
 7120. The method of claim7108, wherein the material comprises a gas.
 7121. The method of claim7108, wherein the material comprises natural gas.
 7122. The method ofclaim 7108, wherein the material comprises compressed air.
 7123. Themethod of claim 7108, wherein the material comprises compressed air, andwherein the compressed air is used as a supplement for electrical powergeneration.
 7124. The method of claim 7108, further comprising:producing at least some of the material from the in situ treatment areathrough a production well; and heating at least a portion of a wellboreof the production well to inhibit condensation of the material withinthe wellbore.
 7125. The method of claim 7108, wherein the in situconversion process comprises pyrolysis.
 7126. The method of claim 7108,wherein the in situ conversion process comprises synthesis gasgeneration.
 7127. The method of claim 7108, wherein the in situconversion process comprises solution mining.
 7128. A method offiltering water within an oil shale formation comprising: providingwater to at least a portion of the formation, wherein the portion haspreviously undergone an in situ conversion process, and wherein thewater comprises one or more components; removing at least one of the oneor more components from the provided water; and producing at least someof the water from the formation.
 7129. The method of claim 7128, whereinat least one of the one or more components comprises a dissolved cation,and further comprising: converting at least some of the provided waterto steam; allowing at least some of the dissolved cation to remain inthe portion of the formation; and producing at least a portion of thesteam from the formation.
 7130. The method of claim 7128, wherein theportion of the formation is above the boiling point temperature of theprovided water at a pressure of the portion, wherein at least one of theone or more components comprises mineral cations, and wherein theprovided water is converted to steam such that the mineral cations aredeposited within the formation.
 7131. The method of claim 7128 furthercomprising converting at least a portion of the provided water intosteam and wherein at least one of the one or more components isseparated from the water as the provided water is converted into steam.7132. The method of claim 7128, wherein a temperature of the portion ofthe formation is greater than about 90° C., and further comprisingsterilizing at least some of the provided water within the portion ofthe formation.
 7133. The method of claim 7128, wherein a temperaturewithin the portion is less than about a boiling temperature of theprovided water at a fluid pressure of the portion.
 7134. The method ofclaim 7128, further comprising remediating at least the one portion ofthe formation.
 7135. The method of claim 7128, wherein the one or morecomponents comprise cations.
 7136. The method of claim 7128, wherein theone or more components comprise calcium.
 7137. The method of claim 7128,wherein the one or more components comprise magnesium.
 7138. The methodof claim 7128, wherein the one or more components comprise amicroorganism.
 7139. The method of claim 7128, wherein the convertedportion of the formation further comprises a pore size such that atleast one of the one or more components is removed from the providedwater.
 7140. The method of claim 7128, wherein the converted portion ofthe formation adsorbs at least one of the one or more components in theprovided water.
 7141. The method of claim 7128, wherein the providedwater comprises formation water.
 7142. The method of claim 7128, whereinthe in situ conversion process comprises pyrolysis.
 7143. The method ofclaim 7128, wherein the in situ conversion process comprises synthesisgas generation.
 7144. The method of claim 7128, wherein the in situconversion process comprises solution mining.
 7145. A method forsequestering carbon dioxide in an oil shale formation, comprising:providing carbon dioxide to a portion of the formation, wherein theportion has previously undergone an in situ conversion process;providing a fluid to the portion; allowing at least some of the providedcarbon dioxide to contact the fluid in the portion; and precipitatingcarbonate compounds.
 7146. The method of claim 7145, wherein providing asolution to the portion comprises allowing groundwater to flow into theportion.
 7147. The method of claim 7145, wherein the solution comprisesone or more dissolved ions.
 7148. The method of claim 7145, wherein thesolution comprises a solution obtained from a formation aquifer. 7149.The method of claim 7145, wherein the solution comprises a man-madeindustrial solution.
 7150. The method of claim 7145, wherein thesolution comprises agricultural run-off.
 7151. The method of claim 7145,wherein the solution comprises seawater.
 7152. The method of claim 7145,wherein the solution comprises a brine solution.
 7153. The method ofclaim 7145, further comprising controlling a temperature within theportion.
 7154. The method of claim 7145, further comprising controllinga pressure within the portion.
 7155. The method of claim 7145, furthercomprising removing at least some of the solution from the formation.7156. The method of claim 7145, further comprising removing at leastsome of the solution from the formation and recycling at least some ofthe removed solution into the formation.
 7157. The method of claim 7145,further comprising providing a buffering compound to the solution. 7158.The method of claim 7145, further comprising: providing the solution tothe formation; and allowing at least some of the solution to migratethrough the formation to increase a contact time between the solutionand the provided carbon dioxide.
 7159. The method of claim 7145, whereinthe solution is provided to the formation after carbon dioxide has beenprovided to the formation.
 7160. The method of claim 7145, furthercomprising providing heat to the portion.
 7161. The method of claim7145, wherein providing carbon dioxide to a portion of the formationcomprises providing carbon dioxide to a first location, whereinproviding a solution to the portion comprises providing the solution toa second location, and wherein the first location is downdip of thesecond location.
 7162. The method of claim 7145, wherein allowing atleast some of the provided carbon dioxide to contact the solution in theportion comprises allowing at least some of the carbon dioxide and atleast some of the solution to migrate past each other.
 7163. The methodof claim 7145, wherein the solution is provided to the formation priorto providing the carbon dioxide, and further comprising providing atleast some of the carbon dioxide to a location positioned proximate alower surface of the portion such that some of the carbon dioxide maymigrate up through the portion.
 7164. The method of claim 7145, whereinthe solution is provided to the formation prior to providing the carbondioxide, and further comprising allowing at least some carbon dioxide tomigrate through the portion.
 7165. The method of claim 7145, furthercomprising: providing heat to the portion, wherein the portion comprisesa temperature greater than about a boiling point of the solution;vaporizing at least some of the solution; producing a fluid from theformation.
 7166. The method of claim 7145, further comprising decreasingleaching of metals from the formation into groundwater.
 7167. A methodof treating an oil shale formation, comprising: injecting a recoveryfluid into a portion of the formation; allowing heat within the recoveryfluid, and heat from one or more heat sources, to transfer to a selectedsection of the formation, wherein the selected section compriseshydrocarbons; mobilizing at least some of the hydrocarbons within theselected section; and producing a mixture from the formation.
 7168. Themethod of claim 7167, wherein the portion has been previously produced.7169. The method of claim 7167, wherein the portion has previouslyundergone an in situ conversion process.
 7170. The method of claim 7167,further comprising upgrading at least some hydrocarbons within theselected section to decrease a viscosity of the hydrocarbons.
 7171. Themethod of claim 7167, wherein the produced mixture compriseshydrocarbons having an average API gravity greater than about 25°. 7172.The method of claim 7167, further comprising vaporizing at least some ofthe hydrocarbons within the selected section.
 7173. The method of claim7167, wherein the recovery fluid comprises water.
 7174. The method ofclaim 7167, wherein the recovery fluid comprises hydrocarbons.
 7175. Themethod of claim 7167, wherein the mixture comprises pyrolyzation fluids.7176. The method of claim 7167, wherein the mixture compriseshydrocarbons.
 7177. The method of claim 7167, wherein the mixture isproduced from a production well and further comprising controlling apressure such that a fluid pressure proximate to the production well isless than about a fluid pressure proximate to a location where the fluidis injected.
 7178. The method of claim 7167, further comprising:monitoring a composition of the produced mixture; and controlling afluid pressure in at least a portion of the formation to control thecomposition of the produced mixture.
 7179. The method of claim 7167,further comprising pyrolyzing at least some of the hydrocarbons withinthe selected section of the formation.
 7180. The method of claim 7167,wherein the average temperature of the selected section is between about275° C. to about 375° C., and wherein a fluid pressure of the recoveryfluid is between about 60 bars to about 220 bars, and wherein therecovery fluid comprises steam.
 7181. The method of claim 7167, furthercomprising controlling pressure within the selected section such that afluid pressure within the selected section is at least about ahydrostatic pressure of a surrounding portion of the formation. 7182.The method of claim 7167, further comprising controlling pressure withinthe selected section such that a fluid pressure within the selectedsection is greater than about a hydrostatic pressure of a surroundingportion of the formation.
 7183. The method of claim 7167, wherein adepth of the selected section is between about 300 m to about 400 m.7184. The method of claim 7167, wherein the mixture comprises pyrolysisproducts.
 7185. The method of claim 7167, further comprising vaporizingat least some of the hydrocarbons within the selected section andwherein the vaporized hydrocarbons comprise hydrocarbons having a carbonnumber greater than about 1 and a carbon number less than about
 4. 7186.The method of claim 7167, further comprising allowing the injectedrecovery fluid to contact a substantial portion of a volume of theselected section.
 7187. The method of claim 7167, wherein the recoveryfluid comprises steam, and wherein the pressure of the injected steam isat least about 90 bars, and wherein the temperature of the injectedsteam is at least about 300° C.
 7188. The method of claim 7167, furthercomprising upgrading at least a portion of the hydrocarbons within theselected section of the formation such that a viscosity of the portionof the hydrocarbons is decreased.
 7189. The method of claim 7167,further comprising separating the recovery fluid from pyrolyzation fluidand distilled hydrocarbons in the formation, and further comprisingproducing the pyrolyzation fluid and distilled hydrocarbons.
 7190. Themethod of claim 7167, wherein the transfer fluid and vaporizedhydrocarbons are separated with membranes.
 7191. The method of claim7167, wherein the selected section comprises a first selected sectionand a second selected section and further comprising: mobilizing atleast some of the hydrocarbons within the selected first section of theformation; allowing at least some of the mobilized hydrocarbons to flowfrom the selected first section of the formation to a selected secondsection of the formation, and wherein the selected second sectioncomprises hydrocarbons; and heating at least a portion of the formationusing one ore more heat sources; pyrolyzing at least some of thehydrocarbons within the selected second section of the formation; andproducing a mixture from the formation.
 7192. The method of claim 7167,wherein a residence time of the recovery fluid in the formation isgreater than about one month and less than about six months.
 7193. Themethod of claim 7167, further comprising: allowing the recovery fluid tosoak in the selected section of the formation for a selected timeperiod; and producing at least a portion of the recovery fluid from theformation.
 7194. A method of treating oil shale formation in situ,comprising: injecting a recovery fluid into the formation; providingheat from one or more heat sources to the formation; allowing the heatto transfer from one or more of the heat sources to a selected sectionof the formation, wherein the selected section comprises hydrocarbons;mobilizing at least some of the hydrocarbons; and producing a mixturefrom the formation, wherein the produced mixture comprises hydrocarbonshaving an average API gravity greater than about 25°.
 7195. The methodof claim 7194, wherein the heat provided from at least one of the one ormore heat sources is transferred to at least a portion of the formationsubstantially by conduction.
 7196. The method of claim 7194, wherein themixture is produced from the formation when a partial pressure ofhydrogen in at least a portion the formation is at least about 0.5 barsabsolute.
 7197. The method of claim 7194, wherein at least one of theone or more of the heat sources comprises a heater.
 7198. The method ofclaim 7194, further comprising pyrolyzing at least some of thehydrocarbons within selected section.
 7199. The method of claim 7194,further comprising pyrolyzing at least some of the mobilizedhydrocarbons.
 7200. The method of claim 7194, wherein the recovery fluidcomprises water.
 7201. The method of claim 7194, wherein the recoveryfluid comprises hydrocarbons.
 7202. The method of claim 7194, whereinthe mixture comprises pyrolyzation fluids.
 7203. The method of claim7194, wherein the mixture comprises steam.
 7204. The method of claim7194, wherein a pressure is controlled such that a fluid pressureproximate to one or more of the heat sources is greater than a fluidpressure proximate to a location where the fluid is produced
 7205. Themethod of claim 7194, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 7206. The method of claim 7194,wherein the heat is provided such that an average temperature in theselected section ranges from approximately about 270° C. to about 375°C.
 7207. The method of claim 7194, further comprising: monitoring acomposition of the produced mixture; and controlling a pressure in atleast a portion of the formation to control the composition of theproduced mixture.
 7208. The method of claim 7207, wherein the pressureis controlled by a valve proximate to a location where the mixture isproduced.
 7209. The method of claim 7207, wherein the pressure iscontrolled such that pressure proximate to one or more of the heatsources is greater than a pressure proximate to a location where themixture is produced.
 7210. The method of claim 7194, wherein a residencetime of the recovery fluid in the formation is less than about one monthto greater than about six months.
 7211. The method of claim 7194,further comprising: allowing the recovery fluid to soak in the selectedsection of the formation for a selected time period; and producing atleast a portion of the recovery fluid from the formation.
 7212. A methodof recovering methane from an oil shale formation, comprising: providingheat from one or more heat sources to at least one portion of theformation, wherein the portion comprises methane; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; and producing fluids from the formation, wherein the producedfluids comprise methane.
 7213. The method of claim 7212, furthercomprising providing a barrier to at least a segment of the formation.7214. The method of claim 7212, further comprising: providing arefrigerant to a plurality of barrier wells to form a low temperaturezone around the portion of the formation; lowering a temperature withinthe low temperature zone to a temperature less than about a freezingtemperature of water; and removing water from the portion of theformation.
 7215. The method of claim 7212, wherein an averagetemperature of the selected section is less than about 100° C.
 7216. Themethod of claim 7212, wherein an average temperature of the selectedsection is less than about a boiling point of water at an ambientpressure in the formation. The method of claim 7212, wherein an amountof methane produced from the formation is in a range from about 1 m³ ofmethane per ton of formation to about 30 m³ of methane per ton offormation.
 7217. The method of claim 7212, wherein the methane producedfrom the formation is used as fuel for an in situ treatment of an oilshale formation.
 7218. The method of claim 7212, wherein the methaneproduced from the formation is used to generate power for electricalheater wells.
 7219. The method of claim 7212, wherein the methaneproduced from the formation is used as fuel for gas fired heater wells.7220. The method of claim 7212, further comprising providing carbondioxide to the treatment area and allowing at least a portion of themethane to desorb.
 7221. The method of claim 7212, wherein the fluidsare produced from the formation when a partial pressure of hydrogen inat least a portion the formation is at least about 0.5 bars absolute.7222. The method of claim 7212, wherein the heat provided from at leastone heat source is transferred to at least a portion of the formationsubstantially by conduction.
 7223. The method of claim 7212, wherein theone or more of the heat sources comprise heaters.
 7224. A method ofrecovering methane from an oil shale formation, comprising: providing abarrier to a portion of the formation, wherein the portion comprisesmethane; removing the water from the portion; and producing fluids fromthe formation, wherein the produced fluids comprise methane.
 7225. Themethod of claim 7224, wherein removing water from the portion comprisespumping at least some water from the formation.
 7226. The method ofclaim 7224, wherein the barrier inhibits migration of fluids into or outof a treatment area of the formation.
 7227. The method of claim 7224,further comprising decreasing a fluid pressure within the portion andallowing at least some of the methane to desorb.
 7228. The method ofclaim 7224, further comprising providing carbon dioxide to the portionand allowing at least some of the methane to desorb.
 7229. The method ofclaim 7224, wherein providing a barrier comprises: providing refrigerantto a plurality of freeze wells to form a low temperature zone around theportion; and lowering a temperature within the low temperature zone to atemperature less than about a freezing temperature of water.
 7230. Themethod of claim 7224, wherein providing a barrier comprises providingrefrigerant to a plurality of freeze wells to form a frozen barrier zoneand wherein the frozen barrier zone hydraulically isolates the treatmentarea from a surrounding portion of the formation.
 7231. The method ofclaim 7224, further comprising: providing heat from one or more heatsources to at least one portion of the formation; and allowing the heatto transfer from the one or more heat sources to a selected section ofthe formation.
 7232. The method of claim 7224, wherein an averagetemperature of the selected section is less than about 100° C.
 7233. Themethod of claim 7224, wherein an average temperature of the selectedsection is less than about a boiling point of water at an ambientpressure in the formation.
 7234. A method of shutting-in an in situtreatment process in an oil shale formation, comprising: terminatingheating from one or more heat sources providing heat to a portion of theformation; monitoring a pressure in at least a portion of the formation;controlling the pressure in the portion of the formation such that thepressure is maintained approximately below a fracturing or breakthroughpressure of the formation.
 7235. The method of claim 7234, whereinmonitoring the pressure in the formation comprises detecting fractureswith passive acoustic monitoring.
 7236. The method of claim 7234,wherein controlling the pressure in the portion of the formationcomprises: producing hydrocarbon vapor from the formation when thepressure is greater than approximately the fracturing or breakthroughpressure of the formation; and allowing produced hydrocarbon vapor tooxidize at a surface of the formation.
 7237. The method of claim 7234,wherein controlling the pressure in the portion of the formationcomprises: producing hydrocarbon vapor from the formation when thepressure is greater than approximately the fracturing or breakthroughpressure of the formation; and storing at least a portion of theproduced hydrocarbon vapor.
 7238. A method of shutting-in an in situtreatment process in an oil shale formation, comprising: terminatingheating from one or more heat sources providing heat to a portion of theformation; producing hydrocarbon vapor from the formation; and injectingat least a portion of the produced hydrocarbon vapor into a portion of astorage formation.
 7239. The method of claim 7238, wherein the storageformation comprises a spent formation.
 7240. The method of claim 7239,wherein an average temperature of the portion of the spent formation isless than about 100° C.
 7241. The method of claim 7239, wherein asubstantial portion of condensable compounds in the injected hydrocarbonvapor condense in the spent formation.
 7242. The method of claim 7238,wherein the storage formation comprises a relatively high temperatureformation, and further comprising converting a substantial portion ofinjected hydrocarbons into coke and molecular hydrogen.
 7243. The methodof claim 7242, wherein the average temperature of the portion of therelatively high temperature formation is greater than about 300° C.7244. The method of claim 7242, further comprising: producing at least aportion of the H₂ from the relatively high temperature formation; andallowing the produced molecular hydrogen to oxidize at a surface of therelatively high temperature formation.
 7245. The method of claim 7238,wherein the storage formation comprises a depleted formation.
 7246. Themethod of claim 7245, wherein the depleted formation comprises an oilfield.
 7247. The method of claim 7245, wherein the depleted formationcomprises a gas field.
 7248. The method of claim 7245, wherein thedepleted formation comprises a water zone comprising seal and trapintegrity.
 7249. A method of producing a soluble compound from a solublecompound containing oil shale formation, comprising: providing heat fromone or more heat sources to at least a portion of a hydrocarboncontaining layer; producing a mixture comprising hydrocarbons from theformation; using heat from the formation, heat from the mixture producedfrom the formation, or a component from the mixture produced from theformation to adjust a quality of a first fluid; providing the firstfluid to a soluble compound containing formation; and producing a secondfluid comprising a soluble compound from the soluble compound containingformation.
 7250. The method of claim 7249, further comprising pyrolyzingat least some hydrocarbons in the hydrocarbon containing layer. 7251.The method of claim 7249, further comprising dissolving the solublecompound in the soluble compound containing formation.
 7252. The methodof claim 7249, wherein the soluble compound comprises a phosphate. 7253.The method of claim 7249, wherein the soluble compound comprisesalumina.
 7254. The method of claim 7249, wherein the soluble compoundcomprises a metal.
 7255. The method of claim 7249, wherein the solublecompound comprises a carbonate.
 7256. The method of claim 7249, furthercomprising separating at least a portion of the soluble compound fromthe second fluid.
 7257. The method of claim 7249, further comprisingseparating at least a portion of the soluble compound from the secondfluid, and then recycling a portion of the second fluid into the solublecompound containing formation.
 7258. The method of claim 7249, whereinheat is provided from the heated formation, or from the mixture producedfrom the formation, in the form of hot water or steam.
 7259. The methodof claim 7249, wherein the quality of the first fluid that is adjustedis pH.
 7260. The method of claim 7249, wherein the quality of the firstfluid that is adjusted is temperature.
 7261. The method of claim 7249,further comprising adding a dissolving compound to the first fluid thatfacilitates dissolution of the soluble compound in the solublecontaining formation.
 7262. The method of claim 7249, wherein CO₂produced from the hydrocarbon containing layer is used to adjust acidityof the solution.
 7263. The method of claim 7249, wherein the solublecompound containing formation is at a different depth than the portionof the hydrocarbon containing layer.
 7264. The method of claim 7249,wherein heat from the portion of the hydrocarbon containing layermigrates and heats at least a portion of the soluble compound containingformation.
 7265. The method of claim 7249, wherein the soluble compoundcontaining formation is at a different location than the portion of thehydrocarbon containing layer.
 7266. The method of claim 7249, furthercomprising using openings for providing the heat sources, and furthercomprising using at least a portion of these openings to provide thefirst fluid to the soluble compound containing formation.
 7267. Themethod of claim 7249, farther comprising providing the solution to thesoluble compound containing formation in one or more openings that werepreviously used to (a) provide heat to the hydrocarbon containing layer,or (b) produce the mixture from the hydrocarbon containing layer. 7268.The method of claim 7249, further comprising providing heat to thehydrocarbon containing layer, or producing the mixture from thehydrocarbon containing layer, using one or more openings that werepreviously used to provide a solution to a soluble compound containingformation.
 7269. The method of claim 7249, further comprising:separating at least a portion of the soluble compound from the secondfluid; providing heat to at least the portion of the soluble compound;and wherein the provided heat is generated in part using one or moreproducts of an in situ conversion process.
 7270. The method of claim7249, further comprising producing the second fluid when a partialpressure of hydrogen in the portion of the hydrocarbon containing layeris at least about 0.5 bars absolute.
 7271. The method of claim 7249,wherein the heat provided from at least one heat source is transferredto at least a part of the hydrocarbon containing layer substantially byconduction.
 7272. The method of claim 7249, wherein one or more of theheat sources comprise heaters.
 7273. The method of claim 7249, whereinthe soluble compound containing formation comprises nahcolite.
 7274. Themethod of claim 7249, wherein greater than about 10% by weight of thesoluble compound containing formation comprises nahcolite.
 7275. Themethod of claim 7249, wherein the soluble compound containing formationcomprises dawsonite.
 7276. The method of claim 7249, wherein greaterthan about 2% by weight of the soluble compound containing formationcomprises dawsonite.
 7277. The method of claim 7249, wherein the firstfluid comprises steam.
 7278. The method of claim 7249, wherein the firstfluid comprises steam, and further comprising providing heat to thesoluble compound containing formation by injecting the steam into theformation.
 7279. The method of claim 7249, wherein the soluble compoundcontaining formation is heated and then the first fluid is provided tothe formation.
 7280. A method of treating an oil shale formation insitu, comprising: providing heat to at least a portion of the formation;allowing the heat to transfer from at least the portion to a selectedsection of the formation such that dissociation of carbonate minerals isinhibited; injecting a first fluid into the selected section; producinga second fluid from the formation; and conducting an in situ conversionprocess in the selected section.
 7281. The method of claim 7280, whereinthe mixture is produced from the formation when a partial pressure ofhydrogen in at least a portion the formation is at least about 0.5 barsabsolute.
 7282. The method of claim 7280, wherein the heat is providedfrom at least one heat source, and wherein the heat is transferred to atleast the portion of the formation substantially by conduction. 7283.The method of claim 7280, wherein the in situ conversion processcomprises: providing additional heat to a least a portion of theformation; pyrolyzing at least some hydrocarbons in the portion; andproducing a mixture from the formation.
 7284. The method of claim 7280,wherein the selected section comprises nahcolite.
 7285. The method ofclaim 7280, wherein the selected section comprises dawsonite.
 7286. Themethod of claim 7280, wherein the selected section comprises trona.7287. The method of claim 7280, wherein the selected section comprisesgaylussite.
 7288. The method of claim 7280, wherein the selected sectioncomprises carbonates.
 7289. The method of claim 7280, wherein theselected section comprises carbonate phosphates.
 7290. The method ofclaim 7280, wherein the selected section comprises carbonate chlorides.7291. The method of claim 7280, wherein the selected section comprisessilicates.
 7292. The method of claim 7280, wherein the selected sectioncomprises borosilicates.
 7293. The method of claim 7280, wherein theselected section comprises halides.
 7294. The method of claim 7280,wherein the first fluid comprises a pH greater than about
 7. 7295. Themethod of claim 7280, wherein the first fluid comprises a temperatureless than about 110° C.
 7296. The method of claim 7280, wherein theportion has previously undergone an in situ conversion process prior tothe injection of the first fluid.
 7297. The method of claim 7280,wherein the second fluid comprises hydrocarbons.
 7298. The method ofclaim 7280, wherein the second fluid comprises hydrocarbons, and furthercomprising: fragmenting at least some of the portion prior to providingthe first fluid; generating hydrocarbons; and providing at least some ofthe second fluid to a surface treatment unit, wherein the second fluidcomprises at least some of the generated hydrocarbons.
 7299. The methodof claim 7280, further comprising removing mass from the selectedsection in the second fluid.
 7300. The method of claim 7280, furthercomprising removing mass from the selected section in the second fluidsuch that a permeability of the selected section increases.
 7301. Themethod of claim 7280, further comprising removing mass from the selectedsection in the second fluid and decreasing a heat transfer time in theselected section.
 7302. The method of claim 7280, further comprisingcontrolling the heat such that the selected section has a temperature ofabove about 120° C.
 7303. The method of claim 7280, wherein the selectedsection comprises nahcolite, and further comprising controlling the heatsuch that the selected section has a temperature less than about adissociation temperature of nahcolite.
 7304. The method of claim 7280,wherein the second fluid comprises soda ash, and further comprisingremoving at least a portion of the soda ash from the second fluid assodium carbonate.
 7305. The method of claim 7280, wherein the in situconversion process comprises pyrolyzing hydrocarbon containing materialin the selected section.
 7306. The method of claim 7280, wherein thesecond fluid comprises nahcolite, and further comprising: separating atleast a portion of the nahcolite from the second fluid; providing heatto at least some of the separated nahcolite to form a sodium carbonatesolution; providing at least some of the sodium carbonate solution to atleast the portion of the formation; and producing a third fluidcomprising alumina from the formation.
 7307. The method of claim 7280,further comprising providing a barrier to at least the portion of theformation to inhibit migration of fluids into or out of the portion.7308. The method of claim 7280, further comprising controlling the heatsuch that a temperature within the selected section of the portion isless than about 100° C.
 7309. The method of claim 7280, furthercomprising: providing additional heat from the one or more heat sourcesto at least the portion of the formation; allowing the additional heatto transfer from at least the portion to the selected section of theformation; pyrolyzing at least some hydrocarbons within the selectedsection of the formation; producing a mixture from the formation;reducing a temperature of the selected section of the formationinjecting a third fluid into the selected section; and producing afourth fluid from the formation.
 7310. The method of claim 7309, whereinthe third fluid comprises water.
 7311. The method of claim 7309, whereinthe third fluid comprises steam.
 7312. The method of claim 7309, whereinthe fourth fluid comprises a metal.
 7313. The method of claim 7309,wherein the fourth fluid comprises a mineral.
 7314. The method of claim7309, wherein the fourth fluid comprises aluminum.
 7315. The method ofclaim 7309, wherein the fourth fluid comprises a metal, and furthercomprising producing the metal from the second fluid.
 7316. The methodof claim 7309, further comprising producing a non-hydrocarbon materialfrom the fourth fluid.
 7317. The method of claim 7280, wherein the firstfluid comprises steam.
 7318. The method of claim 7280, wherein thesecond fluid comprises a metal.
 7319. The method of claim 7280, whereinthe second fluid comprises a mineral.
 7320. The method of claim 7280,wherein the second fluid comprises aluminum.
 7321. The method of claim7280, wherein the second fluid comprises a metal,and further comprisingseparating the metal from the second fluid.
 7322. The method of claim7280, further comprising producing a non-hydrocarbon material from thesecond fluid.
 7323. The method of claim 7280, wherein greater than about10% by weight of the selected section comprises nahcolite.
 7324. Themethod of claim 7280, wherein greater than about 2% by weight of theselected section comprises dawsonite.
 7325. The method of claim 7280,wherein the provided heat comprises waste heat from another portion ofthe formation.
 7326. The method of claim 7280, wherein the first fluidcomprises steam, and further comprising providing heat to the formationby injecting the steam into the formation.
 7327. The method of claim7280, further comprising providing heat to the formation by injectingthe first fluid into the formation.
 7328. The method of claim 7280,further comprising providing heat to the formation by injecting thefirst fluid into the formation, wherein the first fluid is at atemperature above about 90° C.
 7329. The method of claim 7280, furthercomprising controlling a temperature of the selected section whileinjecting the first fluid, wherein the temperature is less than about atemperature at which nahcolite will dissociate.
 7330. The method ofclaim 7280, wherein a temperature within the selected section is lessthan about 90° C. prior to injecting the first fluid to the formation.7331. The method of claim 7280, further comprising providing a barriersubstantially surrounding the selected section such that the barrierinhibits the flow of water into the formation.
 7332. A method oftreating an oil shale formation in situ, comprising: injecting a firstfluid into the selected section; producing a second fluid from theformation; providing heat from one or more heat sources to at least aportion of the formation, wherein the heat is provided after productionof the second fluid has begun; allowing the heat to transfer from atleast a portion of the formation; pyrolyzing at least some hydrocarbonswithin the selected section; and producing a mixture from the formation.7333. The method of claim 7332, wherein the selected section comprisesnahcolite.
 7334. The method of claim 7332, wherein the selected sectioncomprises dawsonite.
 7335. The method of claim 7332, wherein theselected section comprises trona.
 7336. The method of claim 7332,wherein the selected section comprises gaylussite.
 7337. The method ofclaim 7332, wherein the selected section comprises carbonates.
 7338. Themethod of claim 7332, wherein the selected section comprises carbonatephosphates.
 7339. The method of claim 7332, wherein the selected sectioncomprises carbonate chlorides.
 7340. The method of claim 7332, whereinthe selected section comprises silicates.
 7341. The method of claim7332, wherein the selected section comprises borosilicates.
 7342. Themethod of claim 7332, wherein the selected section comprises halides.7343. The method of claim 7332, wherein the first fluid comprises a pHgreater than about
 7. 7344. The method of claim 7332, wherein the firstfluid comprises a temperature less than about 110° C.
 7345. The methodof claim 7332, wherein the second fluid comprises hydrocarbons. 7346.The method of claim 7332, wherein the second fluid compriseshydrocarbons, and further comprising: fragmenting at least some of theportion prior to providing the first fluid; generating hydrocarbons; andproviding at least some of the second fluid to a surface treatment unit,wherein the second fluid comprises at least some of the generatedhydrocarbons.
 7347. The method of claim 7332, further comprisingremoving mass from the selected section in the second fluid.
 7348. Themethod of claim 7332, further comprising removing mass from the selectedsection in the second fluid such that a permeability of the selectedsection increases.
 7349. The method of claim 7332, further comprisingremoving mass from the selected section in the second fluid anddecreasing a heat transfer time in the selected section.
 7350. Themethod of claim 7332, further comprising controlling the heat such thatthe selected section has a temperature of above about 270° C.
 7351. Themethod of claim 7332, wherein the second fluid comprises soda ash, andfurther comprising removing at least a portion of the soda ash from thesecond fluid as sodium carbonate.
 7352. The method of claim 7332,wherein the second fluid comprises nahcolite, and further comprising:separating at least a portion of the nahcolite from the second fluid;providing heat to at least some of the separated nahcolite to form asodium carbonate solution; providing at least some of the sodiumcarbonate solution to at least the portion of the formation; andproducing a third fluid comprising alumina from the formation.
 7353. Themethod of claim 7332, further comprising providing a barrier to at leastthe portion of the formation to inhibit migration of fluids into or outof the portion.
 7354. The method of claim 7332, wherein the first fluidcomprises steam.
 7355. The method of claim 7332, wherein the secondfluid comprises a metal.
 7356. The method of claim 7332, wherein thesecond fluid comprises a mineral.
 7357. The method of claim 7332,wherein the second fluid comprises aluminum.
 7358. The method of claim7332, wherein the second fluid comprises a metal, and further comprisingseparating the metal from the second fluid.
 7359. The method of claim7332, further comprising producing a non-hydrocarbon material from thesecond fluid.
 7360. The method of claim 7332, wherein greater than about10% by weight of the selected section comprises nahcolite.
 7361. Themethod of claim 7332, wherein greater than about 2% by weight of theselected section comprises dawsonite.
 7362. The method of claim 7332,wherein at least some of the provided heat comprises waste heat fromanother portion of the formation.
 7363. The method of claim 7332,wherein the first fluid comprises steam, and further comprisingproviding heat to the formation by injecting the steam into theformation.
 7364. The method of claim 7332, further comprising providingheat to the formation by injecting the first fluid into the formation.7365. The method of claim 7332, further comprising providing heat to theformation by injecting the first fluid into the formation, wherein thefirst fluid is at a temperature above about 90° C.
 7366. The method ofclaim 7332, further comprising controlling a temperature of the selectedsection while injecting the first fluid, wherein the temperature is lessthan about a temperature at which nahcolite will dissociate.
 7367. Themethod of claim 7332, further comprising providing a barriersubstantially surrounding the selected section such that the barrierinhibits the flow of water into the formation.
 7368. The method of claim7332, wherein the mixture is produced from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 7369. The method of claim 7332, wherein theheat provided from at least one heat source is transferred to at least aportion of the formation substantially by conduction.
 7370. The methodof claim 7332, wherein the one or more of the heat sources compriseheaters.
 7371. A method of solution mining alumina from an in situ oilshale formation, comprising: providing heat from one or more heatsources to a least a portion of the formation; pyrolyzing at least somehydrocarbons in the portion; and producing a mixture from the formationproviding a brine solution to a portion of the formation; and producinga mixture comprising alumina from the formation.
 7372. The method ofclaim 7371, wherein the selected section comprises dawsonite.
 7373. Themethod of claim 7371, further comprising: separating at least a portionof the alumina from the mixture; and providing heat to at least theportion of the alumina to generate aluminum.
 7374. The method of claim7371, further comprising: separating at least a portion of the aluminafrom the mixture; providing heat to at least the portion of the aluminato generate aluminum; and wherein the provided heat is generated in partusing one or more products of an in situ conversion process.
 7375. Themethod of claim 7371, further comprising producing the mixture when apartial pressure of hydrogen in the formation is at least about 0.5 barsabsolute.
 7376. The method of claim 7371, wherein the heat provided fromat least one heat source is transferred to at least a portion of theformation substantially by conduction.
 7377. The method of claim 7371,wherein one or more of the heat sources comprise heaters.
 7378. A methodof treating an oil shale formation in situ, comprising: allowing atemperature of a portion of the formation to decrease, wherein theportion has previously undergone an in situ conversion process;injecting a first fluid into the selected section; and producing asecond fluid from the formation.
 7379. The method of claim 7378, whereinthe in situ conversion process comprises: providing heat to a least aportion of the formation; pyrolyzing at least some hydrocarbons in theportion; and producing a mixture from the formation.
 7380. The method ofclaim 7378, wherein the first fluid comprises water.
 7381. The method ofclaim 7378, wherein the second fluid comprises a metal.
 7382. The methodof claim 7378, wherein the second fluid comprises a mineral.
 7383. Themethod of claim 7378, wherein the second fluid comprises aluminum. 7384.The method of claim 7378, wherein the second fluid comprises a metal,and further comprising producing the metal from the second fluid. 7385.The method of claim 7378, further comprising producing a non-hydrocarbonmaterial from the second fluid.
 7386. The method of claim 7378, whereinthe selected section comprises nahcolite.
 7387. The method of claim7378, wherein greater than about 10% by weight of the selected sectioncomprises nahcolite.
 7388. The method of claim 7378, wherein theselected section comprises dawsonite.
 7389. The method of claim 7378,wherein greater than about 2% by weight of the selected sectioncomprises dawsonite.
 7390. The method of claim 7378, wherein theprovided heat comprises waste heat from another portion of theformation.
 7391. The method of claim 7378, wherein the first fluidcomprises steam.
 7392. The method of claim 7378, wherein the first fluidcomprises steam, and further comprising providing heat to the formationby injecting the steam into the formation.
 7393. The method of claim7378, further comprising providing heat to the formation by injectingthe first fluid into the formation.
 7394. The method of claim 7378,further comprising providing heat to the formation by injecting thefirst fluid into the formation, wherein the first fluid is at atemperature above about 90° C.
 7395. The method of claim 7378, whereinthe reduced temperature of the selected section is less than about 90°C.
 7396. The method of claim 7378, wherein an average richness of atleast the portion of the selected section is greater than about 0.10liters per kilogram.
 7397. A method for treating an oil shale formationin situ, comprising: providing heat from one or more heat sources to atleast a portion of the formation; allowing the heat to transfer from theone or more heat sources to a selected section of the formation suchthat the heat pyrolyzes at least some hydrocarbons within the selectedsection; selectively limiting a temperature proximate a selected portionof a heat source wellbore to inhibit coke formation at or near theselected portion; and producing at least some hydrocarbons through theselected portion of the heat source wellbore.
 7398. The method of claim7397, further comprising generating water in the selected portion toinhibit coke formation at or near the selected portion of the heatsource wellbore.
 7399. The method of claim 7397, wherein the heat sourcewellbore is placed substantially horizontally within the selectedsection.
 7400. The method of claim 7397, wherein selectively limitingthe temperature comprises providing less heat at the selected portion ofthe heat source wellbore than other portions of the heat source wellborein the selected section.
 7401. The method of claim 7397, whereinselectively limiting the temperature comprises maintaining thetemperature proximate the selected portion below pyrolysis temperatures.7402. The method of claim 7397, further comprising producing a mixturefrom the selected section through a production well.
 7403. The method ofclaim 7397, further comprising providing at least some heat to anoverburden section of the heat source wellbore to maintain the producedhydrocarbons in a vapor phase.
 7404. The method of claim 7397, furthercomprising maintaining a pressure in the selected section below about150 bars absolute.
 7405. The method of claim 7397, further comprisingproducing hydrocarbons when a partial pressure of hydrogen in theformation is at least about 0.5 bars absolute.
 7406. The method of claim7397, wherein the heat provided from at least one heat source istransferred to at least a portion of the formation substantially byconduction.
 7407. The method of claim 7397, wherein one or more of theheat sources comprise heaters.
 7408. The method of claim 7397, wherein aratio of energy output of the produced mixture to energy input into theformation is at least about
 5. 7409. The method of claim 7397, whereinthe produced mixture comprises an acid number less than about
 1. 7410. Amethod for treating an oil shale formation in situ, comprising:providing heat from one or more heat sources to at least a portion ofthe formation; allowing the heat to transfer from the one or more heatsources to a selected section of the formation such that the heatpyrolyzes at least some hydrocarbons within the selected section;controlling operating conditions at a production well to inhibit cokingin or proximate the production well; and producing a mixture from theselected section through the production well.
 7411. The method of claim7410, wherein controlling the operating conditions at the productionwell comprises controlling heat output from at least one heat sourceproximate the production well.
 7412. The method of claim 7410, whereincontrolling the operating conditions at the production well comprisesreducing or turning off heat provided from at least one of the heatsources for at least part of a time in which the mixture is producedthrough the production well.
 7413. The method of claim 7410, whereincontrolling the operating conditions at the production well comprisesincreasing or turning on heat provided from at least one of the heatsources to maintain a desired quality in the produced mixture.
 7414. Themethod of claim 7410, wherein controlling the operating conditions atthe production well comprises producing the mixture at a locationsufficiently spaced from at least one heat source such that coking isinhibited at the production well.
 7415. The method of claim 7410,further comprising adding steam to the selected section to inhibitcoking at the production well.
 7416. The method of claim 7410, furthercomprising producing the mixture when a partial pressure of hydrogen inthe formation is at least about 0.5 bars absolute.
 7417. The method ofclaim 7410, wherein the heat provided from at least one heat source istransferred to at least a portion of the formation substantially byconduction.
 7418. The method of claim 7410, wherein one or more of theheat sources comprise heaters.
 7419. The method of claim 7410, wherein aratio of energy output of the produced mixture to energy input into theformation is at least about
 5. 7420. The method of claim 7410, whereinthe produced mixture comprises an acid number less than about
 1. 7421. Amethod for treating an oil shale formation in situ, comprising:providing heat from one or more heat sources to at least a portion ofthe oil shale formation; allowing the heat to transfer from the one ormore heat sources to a selected section of the formation such that theheat pyrolyzes at least some hydrocarbons within the selected section;producing a mixture from the selected section; and controlling a qualityof the produced mixture by varying a location for producing the mixture.7422. The method of claim 7421, wherein varying the location forproducing the mixture comprises varying a production location within aproduction well in or proximate the selected section.
 7423. The methodof claim 7422, wherein varying the production location within theproduction well comprises varying a packing height within the productionwell.
 7424. The method of claim 7422, wherein varying the productionlocation within the production well comprises varying a location ofperforations used to produce the mixture within the production well.7425. The method of claim 7421, wherein varying the location forproducing the mixture comprises varying a production location along alength of a production wellbore placed in the formation.
 7426. Themethod of claim 7421, wherein varying the location for producing themixture comprises varying a location of a production well within theformation.
 7427. The method of claim 7421, wherein varying the locationfor producing the mixture comprises varying a number of production wellsin the formation.
 7428. The method of claim 7421, wherein varying thelocation for producing the mixture comprises varying a distance betweena production well and one or more heat sources.
 7429. The method ofclaim 7421, further comprising increasing the quality of the producedmixture by producing the mixture from an upper portion of the selectedsection.
 7430. The method of claim 7421, further comprising increasing atotal mass recovery from the selected section by producing the mixturefrom a lower portion of the selected section.
 7431. The method of claim7421, further comprising selecting the location for production based ona price characteristic for produced hydrocarbons.
 7432. The method ofclaim 7431, wherein the price characteristic is determined bymultiplying a production rate of the produced mixture at a selected APIgravity from the selected section by a price obtainable for selling theproduced mixture with the selected API gravity.
 7433. The method ofclaim 7431, further comprising adjusting the location for productionbased on a change in the price characteristic.
 7434. The method of claim7421, wherein the quality of the produced mixture comprises an APIgravity of the produced mixture.
 7435. The method of claim 7421, whereinthe produced mixture comprises an acid number less than about
 1. 7436.The method of claim 7421, further comprising controlling the quality ofthe produced mixture by controlling the heat provided from at least oneheat source.
 7437. The method of claim 7421, further comprisingcontrolling the quality of the produced mixture such that the producedmixture comprises a selected minimum API gravity.
 7438. The method ofclaim 7421, further comprising producing the mixture when a partialpressure of hydrogen in the formation is at least about 0.5 barsabsolute.
 7439. The method of claim 7421, wherein the heat provided fromat least one heat source is transferred to at least a portion of theformation substantially by conduction.
 7440. The method of claim 7421,wherein one or more of the heat sources comprise heaters.
 7441. Themethod of claim 7421, wherein a ratio of energy output of the producedmixture to energy input into the formation is at least about 5.